Annual Report (foreign Private Issuer) (40-f)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

__________________

Form 40-F

(Check One)

¨ Registration statement pursuant to Section 12 of the Securities Exchange Act of 1934

x Annual report pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934

For the fiscal year ended December 31, 2014

Commission File Number: 001-32179

__________________

INTEROIL CORPORATION

(Exact name of registrant as specified in its charter)

YUKON, CANADA

(Province or other jurisdiction of incorporation or organization)

1311	Not Applicable
(Primary Standard Industrial Classification Code Number)	(I.R.S. Employer Identification Number)

163 PENANG ROAD

#06-02 WINSLAND HOUSE II

SINGAPORE 238463

Telephone Number: +65 6507-0222

(Address and telephone number of registrant’s principal executive offices)

CT Corporation Systems

111 Eighth Avenue

New York, New York 10011

Telephone Number: (212) 894-8940

(Name, address (including zip code) and telephone number

(including area code) of agent for service in the United States)

Copy to:

Geoff Applegate

InterOil Corporation

163 Penang Road

#06-02 Winsland House II

Singapore 238463

Telephone Number: +65 6507-0222

Securities registered or to be registered pursuant to Section 12(b) of the Act:

Title of each class	Name of each exchange on which registered

Common Shares	New York Stock Exchange

Securities registered or to be registered pursuant to Section 12(g) of the Act: None

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act: None

For annual reports, indicate by check mark the information filed with this form:

x Annual Information Form

x Audited Annual Financial Statements

As of December 31, 2014, 49,414,801 of the issuer’s common shares were outstanding.

Indicate by check mark whether the registrant by filing the information contained in this form is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934 (the “Exchange Act”). If “Yes” is marked, indicate the filing number assigned to the registrant in connection with such rule. ¨ Yes 82-______ x No

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the preceding 12 months (or for such shorter period that the registrant was required to file such reports); and (2) has been subject to such filing requirements for the past 90 days. x Yes ¨ No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the Registrant was required to submit and post such files). ¨ Yes ¨ No

FORWARD-LOOKING STATEMENTS

This Annual Report on Form 40-F contains or incorporates by reference forward-looking statements relating to future events or future performance. In some cases, forward-looking statements can be identified by terminology such as "may", "should", "expects", "projects", "plans", "anticipates" and similar expressions. These statements represent management's expectations or beliefs concerning, among other things, future operating results and various components thereof or the economic performance of the InterOil Corporation (the “Company”). Undue reliance should not be placed on these forward-looking statements which are based upon management's assumptions and are subject to known and unknown risks and uncertainties which may cause actual performance and financial results in future periods to differ materially from any projections of future performance or results expressed or implied by such forward-looking statements. Accordingly, readers are cautioned that events or circumstances could cause results to differ materially from those predicted. For a description of some of these risks, uncertainties, events and circumstances, readers should review the disclosure under the heading "Risk Factors" in the Company's Annual Information Form for the year ended December 31, 2014, which is attached as Exhibit 99.1 to this Annual Report on Form 40-F and is incorporated by reference herein. Other than as required by applicable law, the Company undertakes no obligation to update publicly or revise any forward-looking statements contained herein and such statements are expressly qualified by the cautionary statement.

PRINCIPAL DOCUMENTS

The following documents have been filed as part of this Annual Report on Form 40-F (“Report”) for the Company:

A. Annual Information Form

The 2014 Annual Information Form for the Company is incorporated herein by reference.

B. Audited Annual Financial Statements

The audited consolidated financial statements of the Company for the years ended December 31, 2014, 2013 and 2012, including the report of PricewaterhouseCoopers (the Company’s independent registered public accounting firm) with respect thereto, are incorporated herein by reference. These audited consolidated financial statements have been prepared in accordance with International Financial Reporting Standards ("IFRS") as issued by the IASB applicable to the preparation of financial statements.

C. Management’s Discussion and Analysis

The Management Discussion and Analysis for the Company for the year ended December 31, 2014 (“MD&A”) is incorporated herein by reference.

EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

The term “disclosure controls and procedures” is defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended (the “ Exchange Act”). This term refers to the controls and procedures of an issuer that are designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s (the “Commission”) rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Exchange Act is accumulated and communicated to the issuer’s management, including its principal executive and principal financial officer, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

Under the supervision and with the participation of the Company’s management, including the Company’s Chief Executive Officer and Chief Financial Officer, the Company evaluated the effectiveness of the Company’s disclosure controls and procedures. Based on this evaluation, the Company’s Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2014.

MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Responsibility

The Company’s management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act). The Company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with International Financial Reporting Standards.

Inherent Limitations

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Additionally, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of a change in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Assessment

Management, with the participation of the Company’s Chief Executive Officer and Chief Financial Officer, assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2014, using the criteria set forth in the framework established by the Committee of Sponsoring Organizations of the Treadway Commission entitled Internal Controls — Integrated Framework (2013). Based on this assessment, the Company’s management determined that the Company’s internal control over financial reporting was effective as of December 31, 2014.

Management's assessment of the effectiveness of the Company's internal control over financial reporting as of December 31, 2014 has been audited by PricewaterhouseCoopers, an independent registered public accounting firm, as stated in their attestation report included on page 2 of the consolidated financial statements in this Annual Report on Form 40-F.

CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING

Effective July 1, 2014, as a result of Puma Transaction and Cairns Office Closure, we ceased operating approximately 45% of key controls. Consequently, we have relocated all functions in finance and information management from our office in Cairns, Australia, to our offices in Singapore and Papua New Guinea. We also migrated our Information Management Data Centre to a third party location in Sydney, Australia hosted through an Infrastructure as a Service Solution with Telstra. The changes resulted in changes to personnel, associated with operating key controls or modification of processes associated with key controls. These changes have been evaluated against our key account balances, and based on these evaluation, we believe that we have designed adequate and appropriate internal control over financial reporting to ensure that the financial statements are materially accurate for the fiscal year 2014.

Other than the changes resulting from the Puma Transaction and Office Relocation, there have been no changes in internal control over financial reporting during the fiscal year 2014 that have materially affected, or are reasonably likely to materially affect our internal control over financial reporting.

AUDIT COMMITTEE

The Audit Committee of the Company’s Board of Directors is comprised of Mr. Roger Lewis, Sir Wilson Kamit and Dr. Ellis Armstrong. The Board of Directors has affirmatively determined that each member of the Audit Committee is financially literate and is an independent director for purposes of the New York Stock Exchange rules applicable to members of the audit committee. Additionally, the Board of Directors has determined that Mr. Lewis has the accounting or financial management expertise to be considered a “financial expert” as defined by the final rules approved by the Commission implementing the requirements set forth in Section 407 of the Sarbanes-Oxley Act of 2002.

The Commission has indicated that the designation or identification of a person as an "audit committee financial expert" does not (i) mean that such person is an "expert" for any purpose, including without limitation for purposes of Section 11 of the Securities Act of 1933, as amended, (ii) impose on such person any duties, obligations or liability that are greater than the duties, obligations and liability imposed on such person as a member of the audit committee and the board of directors in the absence of such designation or identification, or (iii) affect the duties, obligations or liability of any other member of the audit committee or the board of directors.

CODE OF ETHICS AND BUSINESS CONDUCT

The Company’s Board of Directors has adopted a Code of Ethics and Business Conduct which applies to all directors, officers and employees of the Company. The Board has not granted any waivers to the Code of Ethics and Business Conduct. The Code of Ethics and Business Conduct is accessible on the Company’s website at http://www.interoil.com/governance.asp. Any amendment to or waiver of the Code of Ethics and Business Conduct that applies to the Company’s Chief Executive Officer, Chief Financial Officer, principal accounting officer or controller will also be posted on the Company’s website. During the fiscal year ended December 31, 2014, there were no waivers, including implicit waivers, granted from any provision of the Code of Ethics and Business Conduct that applied to the Company's principal executive officer, principal financial officer, principal accounting officer or controller, or persons performing similar functions.

PRINCIPAL ACCOUNTANT FEES AND SERVICES

Audit Fees. Fees billed for professional services rendered related to the audit of the Company’s annual consolidated financial statements for the fiscal years ended December 31, 2014 and December 31, 2013 by PricewaterhouseCoopers for services that are normally provided by such accountant in connection with statutory or regulatory filings or engagements for such fiscal years were $1,896,489 and $1,978,492, respectively, including out-of-pocket expenses.

Audit-Related Fees. Fees billed for assurance and related services reasonably related to the performance of the audit or review of the Company’s financial statements and not reported under “Audit Fees” were $nil and $665,891 for the fiscal years ended December 31, 2014 and December 31, 2013, respectively. The fee in 2013 related to procedures performed in connection with the quarterly financial reporting of certain subsidiaries of the Company, and work performed on potential secondary listing on capital markets.

Tax Fees. Fees billed for professional services rendered related to tax compliance, tax advice, and tax planning services for the Company for the fiscal years ended December 31, 2014 and December 31, 2013 by PricewaterhouseCoopers were $472,129 and $577,863, respectively.

All Other Fees. Fees billed for professional services rendered related to all other services for the Company for the fiscal years ended December 31, 2014 and December 31, 2013 by PricewaterhouseCoopers were $38,525 and $2,551, respectively. The fees related to the annual license renewal of Comperio, an online library of financial reporting tools and certain tax advice in relation to expatriate benefits and certain transfer pricing documentation.

Pre-Approval. The Audit Committee of the Company’s Board of Directors has adopted a policy that requires pre-approvals of all auditing services, including the compensation and terms of the audit engagement, and all other non-audit services to be performed by the Company’s independent auditors, subject to certain de-minimus exceptions. Non-audit services subject to the de-minimus exceptions described in Section 10A(i)(1)(B) of the Exchange Act may be approved by the Audit Committee prior to the completion of the audit. All of the services provided by the Company’s independent auditors during 2014 and 2013 were pre-approved by the Audit Committee. No hours expended by PricewaterhouseCoopers to audit the Company’s financial statements for the years ended December 31, 2014 and 2013 were attributed to work performed by persons other than full-time, permanent employees of PricewaterhouseCoopers.

OFF BALANCE SHEET ARRANGEMENTS

Please see the section titled “Liquidity and Capital Resources—Off Balance Sheet Arrangements” in the Company’s MD&A, which is incorporated herein by reference.

CONTRACTUAL OBLIGATIONS

Please see the section titled “Liquidity and Capital Resources—Contractual Obligations and Commitments” in the Company’s MD&A, which is incorporated herein by reference.

UNDERTAKING

The Company undertakes to make available, in person or by telephone, representatives to respond to inquiries made by the Commission staff, and to furnish promptly, when requested to do so by the Commission staff, information relating to: the securities registered pursuant to Form 40-F; the securities in relation to which the obligation to file an annual report on Form 40-F arises; or transactions in said securities.

CONSENT TO SERVICE PROCESS

The Company has previously filed a Form F-X in connection with the class of securities in relation to which the obligation to file this Report arises.

disclosure required by new york stock exchange

The Company is classified as a “foreign private issuer” in connection with its listing on the New York Stock Exchange (“NYSE”). As a result, many of the governance rules of the NYSE that apply to U.S. domestic companies do not apply to the Company. However, as a Canadian public company, the Company has in place a system of corporate governance practices that meets Canadian requirements.

Additionally, the NYSE listing standards require foreign private issuers to make certain corporate governance disclosures, including disclosure of any significant differences between its governance practices and the NYSE governance rules. The following is the NYSE required disclosure:

Presiding Director at Meetings of Non-Management Directors. Section 303A.03 of the NYSE Listed Company Manual requires “non-management directors” to schedule regular executive sessions without members of management present. “Non-management directors” are defined in Section 303A.03 as all directors who are not executive officers. The Company schedules executive sessions on a regular basis in which the Company's non-management directors meet without management participation. Mr. Chris Finlayson serves as the presiding director (the “Presiding Director”) at such sessions. The Board of Directors is responsible for determining whether or not each director is independent. The Board of Directors has adopted the director independence standards contained in Section 303A.02 of the NYSE’s Listed Company Manual for the purposes of satisfying the NYSE’s applicable governance requirements.

Communication with Non-Management Directors. Shareholders may send communications to the Company's non-management directors by writing to the Presiding Director, c/o Geoff Applegate, Corporate Secretary, InterOil Corporation, 163 Penang Road, #06-02 Winsland House II, Singapore 238463, Telephone: +65 6507 0222. Communications will be referred to the Presiding Director for appropriate action. The status of all outstanding concerns addressed to the Presiding Director will be reported to the Board of Directors as appropriate.

Audit Committee. Section 303A.06 of the NYSE Listed Company Manual requires listed companies to have an audit committee composed entirely of independent directors. The Company has established an Audit Committee composed entirely of directors who qualify as independent under the requirements of Rule 10A-3 of the Exchange Act, and Section 303A.07 of the NYSE Listed Company Manual. The Company also complies with Canadian Multilateral Instrument 52-110-Audit Committees, which sets out detailed requirements regarding the composition of the Audit Committee and its responsibilities.

Corporate Governance Guidelines. According to Section 303A.09 of the NYSE Listed Company Manual, a listed company must adopt and disclose a set of corporate governance guidelines with respect to specified topics. Such guidelines are required to be posted on the listed company’s website. The Company operates under corporate governance principles that are consistent with the requirements of Section 303A.09 of the NYSE Listed Company Manual, many of which are described under the heading “Statement of Corporate Governance Practice” in the Company’s Annual Information Circular. However, the Company has not codified its corporate governance principles into formal guidelines.

Shareholder Meeting Quorum Requirement. The NYSE governance rules do not contain a minimum quorum requirement for a shareholder meeting, but gives careful consideration to provisions in a listed company’s by-laws that fixes a quorum for a shareholders’ meeting at less than a majority of the outstanding shares. The Company’s quorum requirement is set forth in its By-Laws. A quorum for a meeting of shareholders is present, irrespective of the number of persons actually present at the meeting, if the holder or holders of five percent (5%) of the shares entitled to vote at the meeting are present in person or represented by proxy.

Proxy Delivery Requirement. The NYSE requires the solicitation of proxies and delivery of proxy statements for all shareholder meetings, and requires that these proxies shall be solicited pursuant to a proxy statement that conforms to the Commission’s proxy rules. The Company is a “foreign private issuer” as defined in Rule 3b-4 under the Exchange Act, and the equity securities of the Company are accordingly exempt from the proxy rules set forth in Sections 14(a), 14(b), 14(c) and 14(f) of the Exchange Act. The Company solicits proxies in accordance with applicable rules and regulations in Canada.

Board Committee Mandates. The mandates of the Company’s Audit Committee, Compensation Committee, Reserves Committee and Nominating and Corporate Governance Committee are each available for viewing on the Company’s website at www.interoil.com/governance.asp, and are available in print to any shareholder who requests them. Requests for copies of these documents should be made by contacting Geoff Applegate, Corporate Secretary, InterOil Corporation, 163 Penang Road, #06-02 Winsland House II, Singapore 238463, Telephone: +65 6507 0222.

SIGNATURES

Pursuant to the requirements of the Exchange Act, the Company certifies that it meets all of the requirements for filing on Form 40-F and has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized.

	INTEROIL CORPORATION

	/s/ Michael Hession
	Michael Hession
	Chief Executive Officer

Date: March 17, 2015

EXHIBIT INDEX

The following exhibits have been filed as part of the Annual Report:

EXHIBIT
NUMBER		DESCRIPTION

1.		Annual Information Form for the year ended December 31, 2014.

2.		Audited annual consolidated financial statements for the year ended December 31, 2014.

3.		Management’s Discussion and Analysis for the year ended December 31, 2014.

4.		Consent of PricewaterhouseCoopers dated March 17, 2015.

5.		Consent of GLJ Petroleum Consultants Limited dated March 17, 2015.

6.		Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934.

7.		Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934.

8.		Certification of Chief Executive Officer pursuant to Rule 13a-14(b) or Rule 15d-14(b) of the Securities Exchange Act of 1934 and Section 1350 of Chapter 63 of Title 18 of the United States Code.

9.		Certification of Chief Financial Officer pursuant to Rule 13a-14(b) or Rule 15d-14(b) of the Securities Exchange Act of 1934 and Section 1350 of Chapter 63 of Title 18 of the United States Code.

Exhibit 1

InterOil Corporation

Annual Information Form

For the Year Ended December 31, 2014

March 17, 2015

TABLE OF CONTENTS

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

Annual Information Form INTEROIL CORPORATION 1

PRELIMINARY NOTES

GENERAL

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

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

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

LEGAL NOTICE – FORWARD-LOOKING STATEMENTS

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

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

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

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

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

the inherent uncertainty of oil and gas exploration;

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

the difficulties with recruitment and retention of qualified personnel;

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

landowner claims and disruption;

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

the exploration and production businesses are competitive;

Annual Information Form INTEROIL CORPORATION 2

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

exposure to certain uninsured risks stemming from our operations;

contractual defaults;

weather conditions and unforeseen operating hazards;

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

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

risk of legal action against us; and

law enforcement difficulties.

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

Although we believe that the assumptions underlying our forward-looking statements are reasonable, any of the assumptions could be inaccurate, and, therefore, we cannot assure you that the forward-looking statements will eventuate.

In light of the significant uncertainties inherent in our forward-looking statements, the inclusion of such information should not be regarded as a representation by us or any other person that our objectives and plans will be achieved.

Some of these assumptions and other risks and uncertainties that could cause actual results to differ materially from such forward-looking statements are more fully described under the heading “Risk Factors” in this AIF.

Further, the forward-looking statements contained in this AIF are made as of the date hereof and, except as required by applicable law, we will not update publicly or revise any of these forward-looking statements. The forward-looking statements contained in this AIF are expressly qualified by this cautionary statement.

ABBREVIATIONS AND EQUIVALENCIES

Abbreviations

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

Note:

(1)

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

Annual Information Form INTEROIL CORPORATION 3

(2)

Tcfes may be misleading, particularly if used in isolation. A Tcfe conversion ratio of one barrel of oil to six thousand cubic feet of gas is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

CONVERSION

This table outlines certain standard conversions between Standard Imperial Units and the International System of Units (metric units).

To Convert From	To	Multiply By
Mcf	cubic meters	28.317
cubic meters	cubic feet	35.315
bbls	cubic meters	0.159
cubic meters	bbls	6.289
feet	meters	0.305
meters	feet	3.281
miles	kilometers	1.609
kilometers	miles	0.621
acres	hectares	0.405
hectares	acres	2.471

EXCHANGE RATES

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

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

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

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

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

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

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

Annual Information Form INTEROIL CORPORATION 4

GLOSSARY OF TERMS

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

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

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

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

“Board” means the board of directors of InterOil.

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

“BSP” means Bank of South Pacific Limited.

“CBA” means the Commonwealth Bank of Australia.

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

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

“CSP” means the proposed condensate stripping facilities, including gathering and condensate pipeline, condensate storage and associated facilities which were to have been developed by the CSP Joint Venture, a joint venture with Mitsui pursuant to the Joint Venture Operating Agreement entered into for the proposed condensate stripping facilities with Mitsui, which terminated on February 28, 2013.

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

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

“Credit Suisse” means Credit Suisse A.G.

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

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

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

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

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

“FID” means final investment decision.

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

Annual Information Form INTEROIL CORPORATION 5

“GAAP” means Canadian generally accepted accounting principles.

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

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

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

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

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

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

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

“JVOA” means Joint Venture Operating Agreement.

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

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

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

“Macquarie” means Macquarie Group Limited.

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

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

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

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

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

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

Annual Information Form INTEROIL CORPORATION 6

“NI 52-110” means National Instrument 52-110 – Audit Committees adopted by the Canadian Securities Administrators.

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

“PacLNG” means Pacific LNG Operations Ltd., a company incorporated in the Bahamas.

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

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

“PNGDV” means PNG Drilling Ventures Limited.

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

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

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

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

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

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

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

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

“SocGen” means Societe Generale Hong Kong branch.

“SPA” means sales and purchase agreement.

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

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

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

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

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

“UBS” means UBS A.G.

“USD” means United States dollars.

Annual Information Form INTEROIL CORPORATION 7

“Westpac” means Westpac Bank PNG Limited.

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

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

Annual Information Form INTEROIL CORPORATION 8

CORPORATE STRUCTURE

Name, Address and Incorporation

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

Our registered office

in Canada is located at:

Suite 300,204 Black Street

Whitehorse, Yukon

Y1A 2M9, Canada

Our corporate office

in Singapore is located at:

163 Penang Road,

Winsland House 2, #06-02

Singapore 238463

Our corporate office

in Papua New Guinea is located at:

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

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

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

Inter-corporate Relationships

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

Annual Information Form INTEROIL CORPORATION 9

GENERAL DEVELOPMENT OF THE BUSINESS

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

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

EXPLORATION AND PRODUCTION BUSINESS – THREE YEAR HISTORY

Exploration - Seismic and Drilling

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

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

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

New exploration license applications

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

Airborne Field Survey

We acquired airborne magnetic, gravity and radiometric surveys over PPL 236, PPL 237 and PPL 238 in 2011 with processing of the data having been completed in 2012. During late 2014 final contract negotiations were completed with CGG for acquisition of high resolution airborne Falcon gravity gradiometry over all our licenses. Subsequent to year end, acquisition of these surveys commenced on January 17, 2015.

Seismic

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

In 2014, we acquired seismic data across a number of leads during the Zebra seismic program targeting PPL 476 and across the Antelope field in PRL 15 during the Antelope South (formerly Antelope Deep) appraisal program. We also commenced a geophysical survey (Magnetotellurics) over the Antelope field in PRL 15, Antelope South prospect in PRL 15 with survey extensions into PPL 476, and Mule Deer lead in PPL 475.

Annual Information Form INTEROIL CORPORATION 10

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

Exploration program and appraisal drilling

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

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

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

PPL 474 - Wahoo drilling program

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

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

We intend to resume operations following a detailed review of well engineering, equipment, options, and regulatory approval of our revised plans. We currently expect to recommence drilling in 2015.

PPL 475 – Raptor drilling program

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

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

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

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

PPL 476 – Bobcat drilling program

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

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

Annual Information Form INTEROIL CORPORATION 11

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

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

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

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

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

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

PRL 39 – Triceratops-3 appraisal well

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

Development

Total agreement

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

We retained 35.4839% (net 27.5%, after the State back-in right of 22.5%) of the PRL. Under the transaction with Total, we received $401.3 million as a completion payment, and are entitled to receive payments of $73.3 million upon a FID for an Elk and Antelope LNG Project, and $65.5 million upon the first LNG cargo shipment from such LNG Project.

In addition to these fixed amounts, Total is obliged to make variable payments for resources in PRL 15 that are in excess of 3.5 Tcfe, based on certification by two independent certifiers following the drilling of up to three appraisal wells in PRL 15. Payments for resources greater than 5.4 Tcfe will be paid at certification.

Total will carry 75% of costs relating to our participating interest in a maximum of three appraisal wells (up to a maximum of $50.0 million per well on a 100% basis). Certification of the Elk and Antelope resources under the Total SSA is expected in 2015.

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

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

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

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

Annual Information Form INTEROIL CORPORATION 12

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

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

Pacific Rubiales Energy farm-in

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

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

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

Midstream Liquefaction Joint Venture

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

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

Financing

Unsecured 2.75% convertible notes:

On November 10, 2010, we completed the issuance of $70.0 million of Convertible Notes. The Convertible Notes rank junior to any secured indebtedness and to all existing and future liabilities of us and our subsidiaries, including the Credit Suisse syndicated secured loan facility, trade payables and lease obligations.

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

Annual Information Form INTEROIL CORPORATION 13

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

Credit Suisse-led syndicated secured facility:

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

On June 17, 2014, we replaced our $250.0 million facility with a $300.0 million syndicated, senior secured capital expenditure facility through a consortium of banks led by Credit Suisse. CBA, ANZ, UBS, Macquarie, BSP, BNP and Westpac, each of which was a participating lender under the original facility, in addition to new banks, MUFG and SocGen, support the new facility. The new facility has an annual interest rate of LIBOR plus 5% and matures at the end of 2015. No drawdowns have been made under this facility as at December 31, 2014.

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

Share Buyback:

On July 21, 2014, our Board authorized a share buy-back to be done periodically on the open market to buy up to $50 million of our common shares within the next 12 months based on the stock price and other market factors. We redeemed and terminated 730,000 of our common shares during the year ended December 31, 2014 for a total purchase price of $41.8 million.

BUSINESS STRATEGY

Our strategy is to unlock significant value to shareholders by finding oil and gas safely and competitively; enable its development through the right partnerships, funding and project development capability; and to repeat this process. Running an effective and efficient business is the core component of this strategy. This business model is founded on exploration and drilling discipline and success, strong commercial and project development acumen and being a “partner of choice”. The focus areas for our strategy are to:

Continue to develop as a prudent and responsible business operator

Build on more than 19 years in Papua New Guinea;

Maintain a sound health and safety record;

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

Remain a significant employer in Papua New Guinea.

Enable our discovered resources

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

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

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

Maximize the value of our exploration assets

Manage our exploration program to maximize access to license areas;

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

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

Employ additional drilling rigs to develop existing discoveries.

Position for long-term success

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

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

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

Annual Information Form INTEROIL CORPORATION 14

DESCRIPTION OF OUR BUSINESS

Overview

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

EXPLORATION AND PRODUCTION BUSINESS – DESCRIPTION

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

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

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

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

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

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

Resources

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

Annual Information Form INTEROIL CORPORATION 15

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

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

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

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

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

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

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

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

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

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

Notes:

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

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

Annual Information Form INTEROIL CORPORATION 16

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

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

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

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

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

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

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

Approval from regulatory authorities to develop the resources; and

Determination of economic viability.

Accuracy of Resource Estimates

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

Costs incurred in relation to Exploration and Development activities

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

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

Annual Information Form INTEROIL CORPORATION 17

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

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

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

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

Operated License Commitments, Terms and Expiry

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

Annual Information Form INTEROIL CORPORATION 18

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

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

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

Working interests in licenses

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

Annual Information Form INTEROIL CORPORATION 19

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

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

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

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

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

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

Annual Information Form INTEROIL CORPORATION 20

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

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

Petroleum Retention License 39 (Triceratops Discovery)

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

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

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

Annual Information Form INTEROIL CORPORATION 21

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

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

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

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

Petroleum Retention License 15 (Elk and Antelope Discoveries)

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

Notes:

⁽¹⁾

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

Annual Information Form INTEROIL CORPORATION 22

⁽²⁾

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

⁽³⁾

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

⁽⁴⁾

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

DISCONTINUED OPERATIONS

On June 30, 2014, we completed the Puma Transaction for gross proceeds of $525.6 million, and made a gain on the Puma Transaction of $49.5 million. The subsidiaries sold pursuant to the Puma Transaction were previously included within the Midstream Refining and Downstream segments respectively. In addition, the shipping business which was previously included within the Corporate segment has also been transferred to Puma. Following the Puma Transaction, the results of these operations have been classified as ‘discontinued operations’ and we are no longer organized as separate segments for reporting purposes.

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

Segments		Operations

Upstream		Exploration and Development – Explore, appraise and develop hydrocarbon structures in Papua New Guinea. Proposed activities include commercializing, monetizing and developing oil and gas structures through production facilities, including a liquefied natural gas plant.

Midstream		Refining – Produce refined petroleum products at Napa Napa in Port Moresby, Papua New Guinea, for domestic and export markets.

Downstream		Wholesale and Retail Distribution – Wholesale and retail marketing and distribution of refined petroleum products in Papua New Guinea.

Corporate		Corporate – Support business segments through business development and improvement activities, general services, administration, human resources, executive management, financing and treasury, government affairs and investor relations. This segment also managed our shipping business, which operated two vessels that transport petroleum products within Papua New Guinea and the South Pacific.

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

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

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

Facilities and Major Subcontractors

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

Annual Information Form INTEROIL CORPORATION 23

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

Crude Supply

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

Sales

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

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

Competition

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

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

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

Customers

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

Trading and Risk Management

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

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

Annual Information Form INTEROIL CORPORATION 24

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

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

Three-Year History

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

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

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

Sales

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

Supply of Products

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

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

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

Retail Distribution

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

Annual Information Form INTEROIL CORPORATION 25

Wholesale Distribution

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

Competition

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

Major Customers

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

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

Three-Year History

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

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

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

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

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

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

Annual Information Form INTEROIL CORPORATION 26

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

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

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

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

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

BSP and Westpac Combined Working Capital Facility (Downstream):

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

BSP and Westpac Combined Secured Facility (Downstream):

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

THE ENVIRONMENT AND COMMUNITY RELATIONS

Environmental Protection

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

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

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

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

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

Annual Information Form INTEROIL CORPORATION 27

Environmental and Social Policies

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

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

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

RISK FACTORS

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

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

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

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

Annual Information Form INTEROIL CORPORATION 28

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

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

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

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

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

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

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

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

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

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

Annual Information Form INTEROIL CORPORATION 29

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

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

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

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

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

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

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

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

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

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

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

Annual Information Form INTEROIL CORPORATION 30

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

The exploration and production businesses are competitive.

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

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

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

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

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

Our ability to contract for or otherwise obtain drilling equipment;

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

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

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

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

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

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

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

Annual Information Form INTEROIL CORPORATION 31

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

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

Third parties may default on their contractual obligations to us.

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

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

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

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

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

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

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

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

Annual Information Form INTEROIL CORPORATION 32

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

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

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

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

DIVIDENDS

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

DESCRIPTION OF CAPITAL STRUCTURE

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

Common Shares

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

Preferred Shares

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

Annual Information Form INTEROIL CORPORATION 33

2.75% Convertible Senior Notes

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

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

Shareholder Rights Plan

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

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

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

Options

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

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

Annual Information Form INTEROIL CORPORATION 34

Restricted Stock Units

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

MARKET FOR OUR SECURITIES

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

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

Annual Information Form INTEROIL CORPORATION 35

DIRECTORS AND EXECUTIVE OFFICERS

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

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

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

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

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

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

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

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

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

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

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

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

Jon Ozturgut Singapore	Chief Operating Officer	January 21, 2014

Donald Spector Singapore	Chief Financial Officer	January 22, 2014

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

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

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

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

Annual Information Form INTEROIL CORPORATION 36

Notes:

(1)

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

(2)

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

(3)

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

(4)

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

(5)

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

(6)

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

(7)

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

(8)

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

(9)

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

(10)

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

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

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

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

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

Background to Directors and Executives

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

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

Annual Information Form INTEROIL CORPORATION 37

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

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

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

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

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

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

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

Annual Information Form INTEROIL CORPORATION 38

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

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

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

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

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

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

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

Annual Information Form INTEROIL CORPORATION 39

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

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

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

Cease Trade Orders

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

Bankruptcies

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

Penalties or Sanctions

Annual Information Form INTEROIL CORPORATION 40

Conflicts of Interest

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

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

AUDIT COMMITTEE

Charter of the Audit Committee

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

Composition of the Audit Committee

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

Relevant Education and Experience

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

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

Pre-Approval Policies and Procedures

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

Annual Information Form INTEROIL CORPORATION 41

External Auditor Service Fees

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

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

Notes:

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

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

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

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

LEGAL PROCEEDINGS AND REGULATORY ACTIONS

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

INTERESTS OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS

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

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

MATERIAL CONTRACTS

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

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

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

Annual Information Form INTEROIL CORPORATION 42

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

Farm-In Agreement by PRE

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

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

Total SPA

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

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

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

Completion of the Total SPA remained subject to government approval and the acquisition by InterOil of minority interests in PRL 15. However, on February 27, 2014, Oil Search agreed to acquire shares in certain PacLNG entities that hold a 22.835% interest in PRL 15 for a consideration of $900.0 million plus further contingent payments based on resource certification. Accordingly it became impossible to fulfill one of the conditions precedents to completion of that agreement.

Total SSA

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

Annual Information Form INTEROIL CORPORATION 43

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

Credit Suisse-led Syndicated Term Loan Facility Agreement

In November 2013, we secured a $250.0 million secured syndicated capital expenditure facility, for an approved seismic data acquisition and drilling program. The facility was provided by a group of banks led by Credit Suisse and included CBA, ANZ, UBS, Macquarie, BSP, BNP Paribas and Westpac. The facility is secured by our existing exploration and corporate entities, including InterOil Corporation, SPI (208) Limited, SPI (210) Limited, SPI (220) Limited, SPI Distribution Limited, InterOil Products Limited, InterOil Finance Inc., SPI Exploration and Production Limited, InterOil Corporation PNG Ltd, SPI CSP PNG Limited, InterOil Australia Pty Ltd, InterOil Singapore Pte. Ltd. and InterOil Shipping Pte. Ltd. This facility was fully repaid in April 2014.

On June 17, 2014, we replaced our $250.0 million loan with Credit Suisse with a $300.0 million syndicated, senior secured capital expenditure facility through a consortium of banks led by Credit Suisse. CBA, ANZ, UBS, Macquarie, BSP, BNP and Westpac, each of which was a participating lender under the original facility, in addition to new banks, MUFG and SocGen, support the new facility. The new facility has an annual interest rate of LIBOR plus 5% and matures at the end of 2015. No drawdowns have been made under the new facility as at December 31, 2014.

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

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

EXTRACTIVE INDUSTRIES TRANSPARENCY INITIATIVE

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

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

Annual Information Form INTEROIL CORPORATION 44

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

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

Notes:

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

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

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

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

TRANSFER AGENT AND REGISTRAR

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

Transfer Agent and Registrar

Main Agent

Computershare Investor Services Inc.

100 University Avenue, 9^th Floor

Toronto, Ontario

Canada M5J 2YI

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

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

E-mail: service@computershare.com

Website: www.computershare.com

Co-Transfer Agent (USA)

Computershare Trust Company N.A.

350 Indiana Street

Golden, Colorado 80401

U.S.A.

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

International: 1-514-982-7555

INTERESTS OF EXPERTS

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

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

Annual Information Form INTEROIL CORPORATION 45

ADDITIONAL INFORMATION

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

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

Annual Information Form INTEROIL CORPORATION 46

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

FORM 51-101F3 REPORT OF

MANAGEMENT AND DIRECTORS

ON OIL AND GAS DISCLOSURE

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

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

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

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

(a)

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

(b)

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

(c)

reviewed the reserves data with management and the evaluator.

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

(a)

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

(b)

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

(c)

the content and filing of this report.

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

DATED effective March 17, 2015.

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

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

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

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

“Roger Lewis”
Roger Lewis
Director

Annual Information Form INTEROIL CORPORATION 47

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

REPORT ON RESOURCES DATA

INDEPENDENT QUALIFIED RESERVES

EVALUATOR OR AUDITOR

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

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

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

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

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

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

Company Gross
MMBOE

Independent
Qualified Reserves
Evaluator and Resource
Category

Description and
Preparation
Date of
Assessment
Report

Location of
Reserves
(Country or
Foreign
Geographic Area)

Low

Best

High

Contingent Resources
GLJ Petroleum Consultants

March 13, 2015

Papua New Guinea

744.8

1,002.8

1,241.2

Prospective Resources
GLJ Petroleum Consultants

March 13, 2015

Papua New Guinea

34.9

95.4

185.7

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

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

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

Annual Information Form INTEROIL CORPORATION 48

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

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

EXECUTED as to our report referred to above:

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

Keith M. Braaten, P. Eng.

President & CEO

Annual Information Form INTEROIL CORPORATION 49

Schedule C – Audit Committee Charter

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

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

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

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

Oversee audits of the Company's financial statements.

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

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

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

Report to the Board regularly.

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

Committee Membership.

2.1.

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

2.2.

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

2.3.

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

2.4.

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

Annual Information Form INTEROIL CORPORATION 50

Meetings.

3.1.

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

3.2.

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

3.3.

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

3.4.

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

3.5.

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

3.6.

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

General Review Procedures.

4.1.

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

4.2.

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

Annual Information Form INTEROIL CORPORATION 51

4.3.

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

4.4.

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

4.5.

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

4.6.

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

4.7.

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

4.8.

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

4.9.

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

4.10.

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

4.11.

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

4.12.

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

External auditors.

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

Annual Information Form INTEROIL CORPORATION 52

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

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

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

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

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

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

Annual Information Form INTEROIL CORPORATION 53

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 54

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 55

Exhibit 2

InterOil Corporation

Consolidated Financial Statements

(Expressed in United States dollars)

Years ended December 31, 2014, 2013 and 2012

InterOil Corporation

Consolidated Financial Statements

(Expressed in United States dollars)

Table of contents

Management's Report	3

Report of Independent Registered Public Accounting Firm	4

Consolidated Balance Sheets	5

Consolidated Income Statements	6

Consolidated Statements of Comprehensive Income	7

Consolidated Statements of Changes in Equity	8

Consolidated Statements of Cash Flows	9

Notes to the Consolidated Financial Statements	10

Consolidated Financial Statements INTEROIL CORPORATION 2

InterOil Corporation

Consolidated Financial Statements

(Expressed in United States dollars)

MANAGEMENT’S REPORT

The management of InterOil Corporation is responsible for the financial information and operating data presented in this Annual Report.

The consolidated financial statements have been prepared by management in accordance with International Financial Reporting Standards. When alternative accounting methods exist, management has chosen those it deems most appropriate in the circumstances. Financial statements are not precise as they include certain amounts based on estimates and judgments. Management has determined such amounts on a reasonable basis in order to ensure that the financial statements are presented fairly, in all material respects. Financial information presented elsewhere in this Annual Report has been prepared on a basis consistent with that in the consolidated financial statements.

InterOil Corporation maintains systems of internal accounting and administrative controls. These systems are designed to provide reasonable assurance that the financial information is relevant, reliable and accurate and that the Company’s assets are properly accounted for and adequately safeguarded.

Management, with the participation of the Company’s Chief Executive Officer and Chief Financial Officer, assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2014, using the criteria set forth in the framework established by the Committee of Sponsoring Organizations of the Treadway Commission entitled Internal Controls — Integrated Framework (2013). Based on this assessment, the Company’s management determined that the Company’s internal control over financial reporting was effective as of December 31, 2014.

The effectiveness of the Company’s internal control over financial reporting as at December 31, 2014 has been audited by PricewaterhouseCoopers, Chartered Accountants, as stated in their report which is located on page 4 of InterOil Corporation’s 2014 Annual Financial Statements.

The Audit Committee, appointed by the Board of Directors, is composed of independent non-management directors. The Committee meets regularly with management, as well as the independent auditors, to discuss auditing, internal controls, accounting policy and financial reporting matters. The Committee reviews the annual consolidated financial statements with both management and the independent auditors and reports its findings to the Board of Directors before such statements are approved by the Board of Directors.

The 2014 consolidated financial statements have been audited by PricewaterhouseCoopers, the independent auditors, in accordance with auditing standards issued by the Public Company Accounting Oversight Board, on behalf of the shareholders. PricewaterhouseCoopers has full and free access to the Audit Committee.

/s/ Michael Hession		/s/ Donald Spector
Michael Hession		Donald Spector
Chief Executive Officer		Chief Financial Officer

Consolidated Financial Statements INTEROIL CORPORATION 3

InterOil Corporation

Consolidated Financial Statements

(Expressed in United States dollars)

Report of Independent Registered Public Accounting Firm

To the Shareholders of InterOil Corporation

We have audited the accompanying consolidated financial statements of InterOil Corporation and its subsidiaries, which comprise the Consolidated Balance Sheets as at December 31, 2014, December 31, 2013, and December 31, 2012, and the Consolidated Income Statements, Consolidated Statements of Comprehensive Income, Consolidated Statements of Changes in Equity and Consolidated Statements of Cash Flows for the years then ended, and the related notes, which comprise a summary of significant accounting policies and other explanatory information.

We have also audited InterOil Corporation’s and its subsidiaries’ internal control over financial reporting as at December 31, 2014, based on criteria established in Internal Control - Integrated Framework (2013), issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report. Our responsibility is to express an opinion on these consolidated financial statements and an opinion on the company’s internal control over financial reporting based on our integrated audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the consolidated financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall consolidated financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. 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 generally accepted accounting principles, 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 the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. 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 the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of InterOil and its subsidiaries as of December 31, 2014, December 31, 2013 and December 31, 2012 and the results of their operations and their cash flows for the years then ended in conformity with International Financial Reporting Standards as issued by the International Accounting Standards Board. Also, in our opinion, InterOil and its subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control - Integrated Framework (2013) issued by COSO.

/s/ PricewaterhouseCoopers
PricewaterhouseCoopers
Chartered Accountants
Sydney, Australia
March 17, 2015

Consolidated Financial Statements INTEROIL CORPORATION 4

InterOil Corporation

Consolidated Balance Sheets

(Expressed in United States dollars)

	As at
	December 31,		December 31,			December 31,
	2014		2013			2012
	$		$			$

Assets
Current assets:
Cash and cash equivalents (note 5)		393,405,198		61,966,539			49,720,680
Cash restricted (note 7)		7,959,859		36,149,544			37,340,631
Trade and other receivables (note 8)		566,362,745		98,638,110			161,578,481
Derivative financial instruments (note 4)		-		-			233,922
Other current assets		2,742,316		1,054,847			832,869
Inventories (note 4)		-		158,119,181			194,871,339
Prepaid expenses		2,312,626		8,125,270			8,517,340
Total current assets		972,782,744		364,053,491			453,095,262
Non-current assets:
Cash restricted (note 7)		341,274		17,065,000			11,670,463
Plant and equipment (note 9)		12,263,365		244,383,962			255,031,257
Exploration and evaluation assets (note 10)		325,041,973		584,807,023			510,669,431
Deferred tax assets (note 11)		-		48,230,688			63,526,458
Other non-current receivables (note 15)		29,700,534		29,700,534			5,000,000
Investments accounted for using the equity method (note 23)		-		17,557,838			-
Available-for-sale investments		-		-			4,304,176
Total non-current assets		367,347,146		941,745,045			850,201,785
Total assets		1,340,129,890		1,305,798,536			1,303,297,047
Liabilities and shareholders' equity
Current liabilities:
Trade and other payables (note 12)		139,716,105		134,027,347			178,313,483
Income tax payable		1,809,742		17,087,974			11,977,681
Derivative financial instruments (note 4)		-		1,869,253			-
Working capital facilities (note 4)		-		36,379,031			94,290,479
Unsecured loan and current portion of secured loans (note 13)		-		134,775,077			31,383,115
Current portion of indirect participation interest (note 14)		7,449,409		12,097,363			15,246,397
2.75% convertible notes liability (note 17)		66,501,994		-			-
Total current liabilities		215,477,250		336,236,045			331,211,155
Non-current liabilities:
Secured loans (note 13)		-		65,681,425			89,446,137
2.75% convertible notes liability (note 17)		-		62,662,628			59,046,581
Deferred gain on contributions to LNG project		-		-			5,191,101
Indirect participation interest (note 14)		-		7,449,409			16,405,393
Other non-current liabilities (note 15)		96,000,000		96,000,000			20,961,380
Asset retirement obligations (note 4)		-		4,948,017			4,978,334
Total non-current liabilities		96,000,000		236,741,479			196,028,926
Total liabilities		311,477,250		572,977,524			527,240,081
Equity:
Equity attributable to owners of InterOil Corporation:
Share capital (note 16)		991,693,780		953,882,273			928,659,756
Authorized - unlimited
Issued and outstanding - 49,414,801
(Dec 31, 2013 - 49,217,242)
(Dec 31, 2012 - 48,607,398)
2.75% convertible notes (note 17)		14,297,627		14,297,627			14,298,036
Contributed surplus		18,270,837		26,418,658			21,876,853
Accumulated Other Comprehensive Income		-		4,541,913			25,032,953
Conversion options (note 14)		-		-			12,150,880
Accumulated earnings/(deficit)		4,390,396		(266,319,459	)		(225,961,512	)
Total equity attributable to owners of InterOil Corporation		1,028,652,640		732,821,012			776,056,966
Total liabilities and equity		1,340,129,890		1,305,798,536			1,303,297,047

See accompanying notes to the consolidated financial statements

Consolidated Financial Statements INTEROIL CORPORATION 5

InterOil Corporation

Consolidated Income Statements

(Expressed in United States dollars)

	Year ended
	December 31,			December 31,			December 31,
	2014			2013			2012
	$			$			$

Revenue
Interest (note 19)		1,990,941			70,675			62,013
Other		11,167,960			2,691,807			10,361,135
		13,158,901			2,762,482			10,423,148

Administrative and general expenses		(39,244,509	)		(19,165,214	)		(18,128,999	)
Derivative (losses)/gains		-			(146,100	)		11,457
Legal and professional fees		(14,090,903	)		(9,801,024	)		(3,846,582	)
Exploration costs, excluding exploration impairment (note 10)		(34,529,478	)		(18,793,902	)		(13,901,558	)
Finance costs (note 20)		(29,987,061	)		(13,126,688	)		(6,187,492	)
Depreciation and amortization		(3,628,158	)		(5,733,144	)		(4,044,935	)
Gain on conveyance of exploration and evaluation assets (note 10)		340,540,011			500,071			4,418,170
Gain on available-for-sale investment		-			3,719,907			-
Foreign exchange gains/(losses)		4,420,795			(467,322	)		(419,865	)
Share of net (loss)/profit of joint venture partnership accounted for using the equity method (note 23)		(17,557,838	)		2,275,090			(490,186	)
		205,922,859			(60,738,326	)		(42,589,990	)
Profit/(loss) from continuing operations before income taxes		219,081,760			(57,975,844	)		(32,166,842	)

Income taxes
Current tax expense (note 11)		(562,024	)		(717,238	)		(711,279	)
Deferred tax (expense)/benefit (note 11)		(557,406	)		(222,981	)		390,529
		(1,119,430	)		(940,219	)		(320,750	)

Profit/(loss) for the year from continuing operations		217,962,330			(58,916,063	)		(32,487,592	)

Profit for the year from discontinued operations, net of tax (attibutable to owners of InterOil Corporation) (note 4)		71,802,969			18,558,116			34,091,301
Profit/(loss) for the year		289,765,299			(40,357,947	)		1,603,709

Profit/(loss) is attributable to:
Owners of InterOil Corporation		289,765,299			(40,357,947	)		1,603,709
		289,765,299			(40,357,947	)		1,603,709

Earnings/(loss) per share from continuing and discontinued operations attributable to owners of InterOil Corporation during the year
Basic earnings/(loss) per share
From continuing operations		4.39			(1.21	)		(0.67	)
From discontinued operations		1.45			0.38			0.71
From profit/(loss) for the year		5.84			(0.83	)		0.04
Diluted earnings/(loss) per share
From continuing operations		4.38			(1.21	)		(0.67	)
From discontinued operations		1.44			0.38			0.69
From profit/(loss) for the year		5.82			(0.83	)		0.02
Weighted average number of common shares outstanding
Basic (Expressed in number of common shares)		49,619,048			48,793,986			48,352,822
Diluted (Expressed in number of common shares)		49,728,216			48,793,986			48,352,822

See accompanying notes to the consolidated financial statements

Consolidated Financial Statements INTEROIL CORPORATION 6

InterOil Corporation

Consolidated Statements of Comprehensive Income

(Expressed in United States dollars)

	Year ended
	December 31,			December 31,			December 31,
	2014			2013			2012
	$			$			$

Profit/(loss) for the year		289,765,299			(40,357,947	)		1,603,709

Other comprehensive loss:
Items that may be reclassified to profit or loss:
Exchange loss on translation of foreign operations, net of tax		(3,141,715	)		(20,245,215	)		(5,001,319	)
Reclassification of exchange gains on previously held foreign operations, net of tax		(1,400,198	)		-			-
(Loss)/profit on available-for-sale financial assets, net of tax		-			(245,825	)		653,390
Other comprehensive loss for the year, net of tax		(4,541,913	)		(20,491,040	)		(4,347,929	)
Total comprehensive income/(loss) for the year		285,223,386			(60,848,987	)		(2,744,220	)

Total comprehensive income/(loss) for the year is attributable to:
Owners of InterOil Corporation		285,223,386			(60,848,987	)		(2,744,220	)
		285,223,386			(60,848,987	)		(2,744,220	)

See accompanying notes to the consolidated financial statements

Consolidated Financial Statements INTEROIL CORPORATION 7

InterOil Corporation

Consolidated Statements of Changes in Equity

(Expressed in United States dollars)

	Year ended
	December 31,			December 31,			December 31,
	2014			2013			2012
Transactions with owners as owners:	$			$			$
Share capital
At beginning of year		953,882,273			928,659,756			905,981,614
Issue of capital stock (note 16)		52,432,299			25,222,517			22,678,142
Share buyback (note 16)		(14,620,792	)		-			-
At end of year		991,693,780			953,882,273			928,659,756
2.75% convertible notes
At beginning of year		14,297,627			14,298,036			14,298,036
Conversion of convertible notes during the year (note 17)		-			(409	)		-
At end of year		14,297,627			14,297,627			14,298,036
Contributed surplus
At beginning of year		26,418,658			21,876,853			25,644,245
Fair value of options and restricted stock transferred to share capital		(9,732,565	)		(12,380,121	)		(11,649,459	)
Stock compensation expense		9,662,402			4,770,971			7,882,067
Gain on conversion of 2.75% convertible notes		-			75			-
Share buyback (note 16)		(8,077,658	)		-			-
Waiver of all remaining IPI conversion options (note 14)		-			12,150,880			-
At end of year		18,270,837			26,418,658			21,876,853
Accumulated Other Comprehensive Income
Foreign currency translation reserve
At beginning of year		4,541,913			24,787,128			29,788,447
Foreign currency translation movement for the year, net of tax		(3,141,715	)		(20,245,215	)		(5,001,319	)
Reclassification of exchange gains on previously held foreign operations, net of tax		(1,400,198	)		-			-
Foreign currency translation reserve at end of year		-			4,541,913			24,787,128
Gain/(loss) on available-for-sale financial assets
At beginning of year		-			245,825			(407,565	)
Loss on available-for-sale financial assets as a result of foreign currency translation, net of tax		-			(277,553	)		449,413
Loss on revaluation of available-for-sale financial assets, net of tax		-			(203,977	)		203,977
Gain on disposal of available-for-sale financial assets, net of tax		-			235,705			-
Loss on available-for-sale financial assets at end of year		-			-			245,825
Accumulated other comprehensive income at end of year		-			4,541,913			25,032,953
Conversion options
At beginning of year		-			12,150,880			12,150,880
Transfer of balance to contributed surplus (note 14)		-			(12,150,880	)		-
At end of year		-			-			12,150,880
Accumulated earnings/(deficit)
At beginning of year		(266,319,459	)		(225,961,512	)		(227,565,221	)
Net profit/(loss) for the year		289,765,299			(40,357,947	)		1,603,709
Share buyback (note 16)		(19,055,444	)		-			-
At end of year		4,390,396			(266,319,459	)		(225,961,512	)
Total InterOil Corporation shareholders' equity at end of year		1,028,652,640			732,821,012			776,056,966

See accompanying notes to the consolidated financial statements

Consolidated Financial Statements INTEROIL CORPORATION 8

InterOil Corporation

Consolidated Statements of Cash Flows

(Expressed in United States dollars)

	Year ended
	December 31,			December 31,			December 31,
	2014			2013			2012
	$			$			$

Cash flows generated from (used in):

Operating activities
Net profit/(loss) for the year		289,765,299			(40,357,947	)		1,603,709
Adjustments for non-cash and non-operating transactions
Depreciation and amortization		12,273,860			23,411,336			21,855,228
Deferred tax		1,876,959			15,295,770			(29,450,576	)
Loss on disposal of plant and equipment		620,155			-			-
Gain on conveyance of exploration assets (note 10)		(340,540,011	)		(500,071	)		(4,418,170	)
Gain on sale of subsidiaries (note 4)		(49,537,443	)		-			-
Accretion of convertible notes liability		3,839,366			3,617,760			3,408,951
Amortization of deferred financing costs		8,323,575			4,589,536			598,698
Timing difference between derivatives recognized and settled		373,697			2,103,175			350,061
Stock compensation expense, including restricted stock		9,662,402			4,770,970			7,882,067
Inventory write down		3,947,006			-			322,535
Accretion of asset retirement obligation liability		192,282			356,830			331,096
Accretion of receivable from Total S.A. (note 8)		(24,826,440	)		-			-
Adjustment to carrying amount of receivable from Total S.A. (note 8)		24,206,783			-			-
Accounts receivable provision and write down		1,709,139			-			-
Non-cash settlement on PNGEI buyback		-			6,837,000			-
Gain on conversion of convertible notes		-			(500	)		-
Gain on Flex LNG investment		-			(3,719,907	)		-
Share of net loss/(profit) of joint venture partnership accounted for using the equity method (note 23)		17,557,838			(2,275,090	)		490,186
Unrealized foreign exchange gain		(1,403,197	)		(352,348	)		(1,070,269	)
Change in operating working capital
Increase in trade and other receivables		(65,585,657	)		(21,273,999	)		(43,579,657	)
Decrease/(increase) in other current assets and prepaid expenses		483,658			170,092			(3,010,564	)
Decrease/(increase) in inventories		8,275,985			30,610,288			(28,886,641	)
Increase in trade and other payables		17,579,089			47,360,333			25,912,734
Net cash (used in)/generated from operating activities		(81,205,655	)		70,643,228			(47,660,612	)

Investing activities
Expenditure on oil and gas properties		(457,393,642	)		(128,285,583	)		(179,779,865	)
Proceeds from joint venture cash calls		129,633,143			29,942,167			3,497,542
Expenditure on plant and equipment		(11,674,329	)		(25,951,297	)		(30,855,107	)
Proceeds from Total for interest in PRL 15 (note 10)		401,338,497			-			-
Proceeds from Pacific Rubiales Energy (conveyance accounted portion)		-			-			20,000,000
Maturity of short term treasury bills		-			-			11,832,110
Proceeds from disposal of Flex LNG Ltd shares, net of transaction costs		-			7,778,258			-
Decrease/(increase) in restricted cash held as security on borrowings		44,913,411			(4,203,450	)		(9,760,331	)
Proceeds from sale of subsidiaries, net of transaction costs, settlement of intercompany debt and cash and cash equivalents disposed of (note 4)		427,985,105			-			-
Change in non-operating working capital
Decrease in trade and other receivables		-			5,000,000			5,000,000
Increase/(decrease) in trade and other payables		105,334,004			(17,744,539	)		22,115,815
Net cash generated from/(used in) investing activities		640,136,189			(133,464,444	)		(157,949,836	)

Financing activities
Repayments of OPIC secured loan		-			-			(35,500,000	)
(Repayments to)/proceeds from Mitsui for Condensate Stripping Plant		-			(34,375,748	)		3,578,489
Proceeds from Westpac secured loan		-			-			15,000,000
Repayments of Westpac secured loan		-			(12,857,000	)		(2,143,000	)
Proceeds from drawdown of BSP and Westpac secured facility,net of transaction costs		-			33,835,101			-
Repayments of BSP and Westpac secured facility		(24,780,077	)		(11,070,578	)		-
Proceeds from drawdown of Credit Suisse secured facility, net of transaction costs		50,000,000			93,042,488			-
Repayment of Credit Suisse secured facility		(150,000,000	)		-			-
Proceeds from Pacific Rubiales Energy for interest in PPL237		-			73,600,000			20,000,000
Proceeds from/(repayments of) working capital facility		20,855,406			(57,911,448	)		77,809,976
(Repayments of)/proceeds from ANZ, BSP & BNP syndicated loan		(84,000,000	)		(16,000,000	)		95,924,091
Proceeds from issue of common shares, net of transaction costs		2,186,690			6,839,930			11,028,683
Payment on share buyback		(41,753,894	)		-			-
Payment on conversion of convertible notes		-			(1,546	)		-
Net cash (used in)/generated from financing activities		(227,491,875	)		75,101,199			185,698,239

Increase/(decrease) in cash and cash equivalents		331,438,659			12,279,983			(19,912,209	)
Cash and cash equivalents, beginning of year		61,966,539			49,720,680			68,575,269
Exchange losses on cash and cash equivalents		-			(34,124	)		1,057,620
Cash and cash equivalents, end of year		393,405,198			61,966,539			49,720,680
Comprising of:
Cash on Deposit		61,073,191			31,738,440			49,086,353
Short Term Deposits		332,332,007			30,228,099			634,327
Total cash and cash equivalents, end of year		393,405,198			61,966,539			49,720,680

See accompanying notes to the consolidated financial statements

Consolidated Financial Statements INTEROIL CORPORATION 9

InterOil Corporation

Notes to Consolidated Financial Statements

(Expressed in United States dollars)

General information

InterOil Corporation (the "Company" or "InterOil") is a publicly traded, oil and gas exploration and production company operating in Papua New Guinea (“PNG”). The Company is incorporated and domiciled in Canada and was continued under the Business Corporations Act (Yukon Territory) on August 24, 2007. The address of its registered office is 300-204 Black Street, Whitehorse, Yukon, Canada.

These consolidated financial statements were approved by the Directors for issue on March 12, 2015. The boards of directors have the power to amend and reissue the financial report.

Discontinued Operations

Management had previously organized the Company’s operations into four major segments - Upstream, Midstream, Downstream and Corporate. Upstream included exploration, appraisal and development of hydrocarbon structures in PNG. Midstream consisted of both Midstream Refining and Midstream Liquefaction. Midstream Refining included production of refined petroleum products at Napa Napa in Port Moresby, PNG, for the domestic market and export markets, and Midstream Liquefaction included the work being undertaken to develop, in joint venture as a non-operator, liquefaction and associated facilities in PNG for the export of liquefied natural gas. The Downstream segment marketed and distributed refined products domestically in PNG on a wholesale and retail basis. The Corporate segment provided support to our other business segments through business development and improvement activities, general services, administration, human resources, executive management, financing and treasury, government affairs and investor relations. This segment also managed our shipping business, which operated two vessels that transport petroleum products for the Downstream segment and external customers, both within PNG and for export in the South Pacific region.

On June 30, 2014, the Company entered into share sale and purchase agreements with Puma Energy Pacific Holdings Pte Ltd (“Puma”) for the sale of InterOil subsidiaries that held the oil refinery and petroleum products distribution businesses, which were previously included within the Midstream Refining and Downstream segments, respectively. As a result of the transaction, as of June 30, 2014, the Company’s operations no longer include the Midstream Refining or Downstream segment and these business have been classified as discontinued operations in these consolidated financial statements. In addition, the shipping business which was previously included within the Corporate segment has also been classified as a discontinued operation in these consolidated financial statements as the activities previously being carried out by that business have been transferred to Puma with the sale of the refining and distribution businesses. Refer to note 4 for further information on the sale of the oil refinery and petroleum products distribution businesses. At December 31, 2014, no additional discontinued operations have been recognized.

Significant accounting policies

The principal accounting policies applied in the preparation of these consolidated financial statements are set out below. These policies have been consistently applied to all the years presented, unless otherwise stated.

(a)

Basis of preparation

The consolidated financial statements of the Company have been prepared in accordance with International Financial Reporting Standards (“IFRS”), as issued by the IASB. The consolidated financial statements for the year ended December 31, 2014 have been prepared under the historical cost convention, except for derivative financial instruments and available-for-sale investments which are measured at fair value.

The preparation of financial statements requires the use of certain critical accounting estimates. It also requires management to exercise its judgment in the process of applying the Company’s accounting policies. Estimates and judgments are continually evaluated and are based on historical experience and other factors, including expectations of future events that are believed to be reasonable under the circumstances. The Company makes estimates and assumptions concerning the future. The resulting accounting estimates will, by definition, seldom equal the related actual results. The estimates and assumptions that have a significant risk of causing a material adjustment to the carrying amounts of assets and liabilities within the next financial year are addressed below.

Convertible notes: The convertible notes are assessed based on the substance of the contractual arrangement in determining whether it exhibits the fundamental characteristic of a financial liability or equity. Management has assessed that the note instrument mainly exhibits characteristics that are liability in nature, however, the embedded conversion feature is equity in nature and needs to be bifurcated and disclosed separately within equity. Management valued the liability component first and assigned the residual value to the equity component. Management fair valued the liability component by deducting the premium paid by holders specifically for the conversion feature. The conversion price of $95.625 per share includes a premium of 27.5% to the issue price of the concurrent common shares offering of $75 per share. Therefore, the $70,000,000 total issue represents 127.5% of the liability portion.

Consolidated Financial Statements INTEROIL CORPORATION 10

InterOil Corporation

Notes to Consolidated Financial Statements

(Expressed in United States dollars)

Significant accounting policies (cont’d)

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

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

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

The conveyance accounting for the share sale agreement (“Total SSA”) with Total S.A. (“Total”) has been accounted for in the year ended December 31, 2014. This recognized the interim resource certification payments expected in addition to the completion payment that was received from Total during the year. The interim resource certifications were estimated based on a certification provided by Gaffney Cline & Associates (“GCA”), which certified a best case scenario of 7.1 trillion standard cubic feet equivalent (“Tcfe”) of natural gas in the Elk and Antelope fields. GCA is a recognized certifier under the Total SSA. The interim resource certification under the Total SSA will vary post the completion of up to three appraisal wells that will be drilled within Elk and Antelope fields prior to the certification.

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

(b)

Statement on liquidity, capital resources and capital requirements

These consolidated financial statements have been prepared on a going concern basis, which contemplates the realization of assets and settlement of liabilities in the normal course of business as they become due.

The net current assets as at December 31, 2014 amounted to $757.3 million compared to $27.8 million as at December 31, 2013 and $121.9 million as at December 31, 2012. The Company has cash, cash equivalents and cash restricted of $401.4 million as at December 31, 2014 (December 2013 - $115.2 million, December 2012 - $98.7 million), of which $8.3 million is restricted (December 2013 - $53.2 million, December 2012 - $49.0 million).

The Company’s primary use of capital resources has been the exploration and development activities. The Company has to execute exploration activities within a set timeframe to meet the minimum license commitments in relation to the Company’s Petroleum Prospecting Licenses (“PPLs”) and Petroleum Retention Licenses (“PRLs”). Refer to note 25 for further information on these commitments. Subject to meeting the license commitment requirements, the Company’s capital expenditure can be accelerated or decelerated at its discretion.

Consolidated Financial Statements INTEROIL CORPORATION 11

InterOil Corporation

Notes to Consolidated Financial Statements

(Expressed in United States dollars)

Significant accounting policies (cont’d)

Existing cash balances will be sufficient to settle debt obligations and to facilitate further necessary development of the Elk and Antelope fields, appraisal of Triceratops field and exploration activities planned to meet our license commitment requirements. However, oil and gas exploration and development and liquefaction are capital intensive and our business plans involve raising capital, which depends on market conditions when we raise such capital. Additionally, our joint venture share of the costs of construction of an LNG plant and other infrastructure associated with a proposed LNG plant may amount to hundreds of millions of dollars and thus exceed our existing cash balances. No assurance can be given that we will be successful in obtaining new capital on terms that are acceptable to us, particularly with market volatility. Accordingly, these consolidated financial statements have been prepared on a going concern basis in the belief that the Company will realize its assets and settle its liabilities and commitments in the normal course of business and for at least the amounts stated, for a period not less than one year from the date of signing this financial report.

(c)

Accounting policies

The accounting policies followed in these consolidated financial statements are consistent with those of the previous financial year.

(d)

New standards issued but not yet effective

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

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

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

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

(e)

Principles of consolidation

Business combinations: The Company applies the acquisition method to account for business combinations. The consideration transferred for the acquisition of a subsidiary is the fair value of the assets transferred, the liabilities incurred to the former owners of the acquiree and the equity interests issued by the group. The consideration transferred includes the fair value of any asset or liability resulting from a contingent consideration arrangement. Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured initially at their fair values at the acquisition date. The Company recognizes any non-controlling interest in the acquiree on an acquisition-by-acquisition basis, either at fair value or at the non-controlling interest’s proportionate share of the recognized amounts of acquiree’s identifiable net assets.

If the business combination is achieved in stages, the acquisition date fair value of the acquirer’s previously held equity interest in the acquiree is re-measured to fair value at the acquisition date through profit or loss. Any contingent consideration to be transferred by the Company is recognized at fair value at the acquisition date. Subsequent changes to the fair value of the contingent consideration that is deemed to be an asset or liability is recognized in accordance with IAS 39 either in profit or loss or as a change to other comprehensive income. Contingent consideration that is classified as equity is not re-measured, and its subsequent settlement is accounted for within equity. The Company measures goodwill at the acquisition date as the fair value of the consideration transferred including the recognized amount of any non-controlling interests in the acquiree, less the fair value of the identifiable assets acquired and liabilities assumed, all measured as of the acquisition date.

Transaction costs, other than those associated with the issue of debt or equity securities, that the Company incurs in connection with a business combination are expensed as incurred.

Subsidiaries: The consolidated financial statements of the Company incorporate the assets, liabilities and results of InterOil Corporation and of all subsidiaries as at December 31, 2014, December 31, 2013 and December 31, 2012, and for the periods then ended.

Consolidated Financial Statements INTEROIL CORPORATION 12

InterOil Corporation

Notes to Consolidated Financial Statements

(Expressed in United States dollars)

Significant accounting policies (cont’d)

On June 30, 2014, the Company entered into two share sale and purchase agreements with Puma for the sale of InterOil subsidiaries that hold the oil refinery and petroleum products distribution businesses, which were previously included within the Midstream Refining and Downstream segments respectively. Specifically, the agreements resulted in the sale by South Pacific Refining Limited, a wholly owned subsidiary of InterOil Corporation, of all shares held by it in EP InterOil Limited (EPI) and SPI Limited, and sale by SPI Distribution of all shares held by it in InterOil Products Limited (IPL) to Puma. In addition, EPI holds 100% of the shares in InterOil Limited (IOL) and as such, ultimate ownership of IOL has also been transferred to Puma. As a result of the transaction, as of June 30, 2014, these sold subsidiaries have been de-consolidated from the results of the Company. The results of operations for these sold businesses have been presented as discontinued operations in the consolidated income statements for the years ended December 31, 2014, 2013 and 2012. In addition, the shipping business which was previously included within the Corporate segment has also been classified as a discontinued operation in the consolidated income statements for the years ended December 31, 2014, 2013 and 2012, as the activities previously being carried out by the business have been transferred to Puma with the sale of the refining and distribution businesses. There has been no loss incurred on transferring the activities previously undertaken by the shipping business.

Subsidiaries of InterOil Corporation as at December 31, 2014 included SPI Exploration and Production Corporation (100%), InterOil Singapore Pte Ltd (100%), InterOil Corporate PNG Limited (100%), South Pacific Refining Limited (100%), SPI Distribution Limited (100%), InterOil LNG Holdings Inc. (100%), InterOil Australia Pty Ltd (100%), Direct Employment Services Company (100%), InterOil Finance Inc. (100%), InterOil Shipping Pte Ltd (100%) and their subsidiaries. InterOil Corporation and its subsidiaries together are referred to in these consolidated financial statements as the Company or the Consolidated Entity.

Subsidiaries are all those entities (including structured entities) over which the Company has control. The Company controls an entity when the Company is exposed to, or has rights to, variable returns from its involvement with the entity and has the ability to affect those returns through its power over the entity. Subsidiaries are fully consolidated from the date on which control is transferred to the Company. They are de-consolidated from the date that control ceases.

Intercompany transactions, balances and unrealized gains on transactions between companies are eliminated on consolidation. Non-controlling interests in the results and equity of subsidiaries are shown separately in the consolidated income statements, statements of comprehensive income, balance sheets and statement of changes in equity.

In March 2012, Champion No. 57 Limited was incorporated in PNG as a 100% subsidiary of SPI (220) Limited to hold an interest in the Triceratops field. This company underwent a change of name, and is currently registered as InterOil Partners Limited. There have been no transactions in this entity as of December 31, 2014.

Joint arrangements: Under IFRS 11, investments in joint arrangements are classified as either joint operations or joint ventures depending on the contractual rights and obligations of each investor. The Company’s interest in PNG LNG Inc. is governed by a shareholders’ agreement signed on July 30, 2007 between the parties to the Joint Venture. The Company has assessed the nature of its joint arrangement and determined it to be a joint venture. Joint ventures are accounted for using the equity method.

Under the equity method of accounting, interests in joint ventures are initially recognized at cost and adjusted thereafter to recognize the Company’s share of the post-acquisition profits or losses and movements in other comprehensive income. When the Company’s share of losses in a joint venture equals or exceeds its interests in the joint venture (which includes any long-term interests that, in substance, form part of the Company’s net investment in the joint venture), the Company does not recognize further losses, unless it has incurred obligations or made payments on behalf of the joint venture.

Unrealized gains on transactions between the Company and its joint venture are eliminated to the extent of the Company’s interest in the joint venture. Any unrealized gains relating to third party interest in the joint venture are deferred until the Company believes that all the conditions for the joint venture to realize those benefits from the transactions with the Company have been met. Unrealized losses are also eliminated unless the transaction provides evidence of an impairment of the asset transferred.

Consolidated Financial Statements INTEROIL CORPORATION 13

InterOil Corporation

Notes to Consolidated Financial Statements

(Expressed in United States dollars)

Significant accounting policies (cont’d)

(f)

Segment reporting

An operating segment is a component of an enterprise:

that engages in business activities from which it may earn revenues and incur expenses (including revenues and expenses relating to transactions with other segments of the same enterprise),

whose operating results are regularly reviewed by the chief operating decision maker to make decisions about resources to be allocated to the segment and assess its performance, and

for which discrete financial information is available.

Segment capital expenditure is the total cost incurred during the period to acquire property, plant and equipment, and intangible assets other than goodwill.

Post the completion of the sale of operations to Puma on June 30, 2014, the Company is no longer organized as separate segments with the continuing operations considered to be an Upstream Exploration and Production business. The Company has concluded that no segment reporting would be applicable post June 30, 2014 as there is no separate financial information available that is evaluated regularly by the chief operating decision maker in deciding how to allocate resources and in assessing performance. The operations of the Company are also concentrated in PNG.

(g)

Foreign currency

Functional and presentation currency: These consolidated financial statements are presented in United States Dollars (“USD”) which is InterOil’s functional and presentation currency.

Foreign currency transactions: Transactions in foreign currencies are translated to the respective functional currencies of Company entities at exchange rates at the dates of the transactions. Monetary assets and liabilities denominated in foreign currencies at the reporting date are retranslated to the functional currency at the exchange rate at that date. The foreign currency gain or loss on monetary items is the difference between amortized cost in the functional currency at the beginning of the period, adjusted for effective interest and payments during the period, and the amortized cost in foreign currency translated at the exchange rate at the end of the period. Non-monetary assets and liabilities denominated in foreign currencies that are measured at fair value are retranslated to the functional currency at the exchange rate at the date that the fair value was determined. Non-monetary items in a foreign currency that are measured in terms of historical cost are translated using the exchange rate at the date of the transaction. Foreign currency differences arising on retranslation are recognized in profit or loss.

Foreign operations: For subsidiaries considered to be foreign operations, all assets and liabilities denominated in foreign currency are translated to USD at exchange rates in effect at the balance sheet date and all revenue and expense items are translated at the rates of exchange in effect at the time of the transactions. Foreign exchange gains or losses are recognized and presented in other comprehensive income and in the foreign currency translation reserve in equity. Goodwill and fair value adjustments arising on the acquisition of a foreign operation are treated as assets and liabilities of the foreign operation and translated at the closing rate.

(h)

Financial instruments

(i) Non-derivative financial assets

The Company initially recognizes loans, receivables and deposits on the date that they are originated. All other financial assets (including assets designated at fair value through profit or loss) are recognized initially on the trade date at which the Company becomes a party to the contractual provisions of the instrument. The Company derecognizes a financial asset when the contractual rights to the cash flows from the asset expire, or it transfers the rights to receive the contractual cash flows on the financial asset in a transaction in which substantially all the risks and rewards of ownership of the financial asset are transferred. Any interest in transferred financial assets that is created or retained by the Company is recognized as a separate asset or liability.

Financial assets and liabilities are offset and the net amount presented in the balance sheet when, and only when, the Company has a legal right to offset the amounts and intends to either settle on a net basis or to realize the asset and settle the liability simultaneously. The Company classifies non-derivative financial assets into the following categories: financial assets at fair value through profit or loss, loans or receivables, held to maturity financial assets and available-for-sale financial assets.

Consolidated Financial Statements INTEROIL CORPORATION 14

InterOil Corporation

Notes to Consolidated Financial Statements

(Expressed in United States dollars)

Significant accounting policies (cont’d)

Loans and receivables: Loans and receivables are financial assets with fixed or determinable payments that are not quoted in an active market. Such assets are recognized initially at fair value plus any directly attributable transaction costs. Subsequent to initial recognition loans and receivables are measured at amortized cost using the effective interest method, less any impairment losses. Loans and receivables comprise of trade and other receivables.

Held-to-maturity: Held-to-maturity investments are non-derivative financial assets with fixed or determinable payments and fixed maturities that the Company’s management has the positive intention and ability to hold to maturity. Held-to-maturity financial assets are recognized initially at fair value plus any directly attributable transaction costs. Subsequent to initial recognition, held-to-maturity financial assets are measured at amortized cost using the effective interest method, less any impairment losses. If the Company were to sell other than an insignificant amount of held-to-maturity financial assets, the whole category would be tainted and reclassified as available-for-sale. Held-to-maturity financial assets are included in non-current assets, except for those with maturities less than 12 months from the end of the reporting period, which are classified as current assets.

Available-for-sale: Available-for-sale financial assets are non-derivative financial assets that are designated as available for sale or are not classified in any of the other categories. The Company’s investments in equity securities are classified as available-for-sale financial assets. Subsequent to initial recognition, they are measured at fair value and changes therein, other than impairment losses, are recognized in other comprehensive income. When an investment is derecognized, the gain or loss accumulated in equity is reclassified to profit or loss.

(ii) Non-derivative financial liabilities

The Company initially recognizes debt securities issued and subordinated liabilities on the date that they originated. All other financial liabilities (including liabilities designated at fair value through profit or loss) are recognized initially on the trade date at which the Company becomes a party to the contractual provisions of the instrument. The Company derecognizes a financial liability when its contractual obligations are discharged or cancelled or expire. Financial assets and liabilities are offset and the net amount presented in the balance sheet when, and only when, the Company has a legal right to offset the amounts and intends to either settle on a net basis or to realize the asset and settle the liability simultaneously.

The Company classifies non-derivative financial liabilities into the other financial liabilities category. Financial liabilities not designated at fair value through profit or loss are recognized initially at fair value plus any directly attributable transaction costs. Subsequent to initial recognition, these financial liabilities are measured at amortized cost using the effective interest method. Other financial liabilities comprise secured and unsecured loans, bank overdrafts, and trade and other payables. Trades and other payables represent liabilities for goods and services provided to the Company prior to the end of financial period which are unpaid. These amounts are unsecured and are usually paid within 30 days of recognition.

(iii) Derivative financial instruments

Derivative financial instruments may be utilized by the Company in the management of its foreign exchange requirements, and prior to the sale of the refining and distribution businesses, to manage its crude purchase cost exposures and its finished products sales price exposures. The Company's policy is not to utilize derivative financial instruments for trading or speculative purposes. The Company may choose to designate derivative financial instruments as hedges.

When applicable, at the inception of the hedge, the Company formally documents all relationships between hedging instruments and the hedged items, as well as its risk management objective and strategy for undertaking various hedge transactions, the nature of the risk being hedged, how the hedging instruments’ effectiveness in offsetting the hedged risk will be assessed and a description of the method for measuring effectiveness. This process includes linking all derivatives to specific assets and liabilities on the balance sheet or to specific firm commitments or anticipated transactions. The Company also assesses whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in fair value or cash flows of hedged items at inception and on an ongoing basis.

Changes in the fair value of a derivative that is highly effective and that is designated and qualifies as a cash-flow hedge are recorded as a component of Other Comprehensive Income until earnings are affected by the variability in cash flows of the designated hedged item. For cash flow hedges that have been terminated or cease to be effective, prospective gains or losses on the derivative are recognized in earnings. Any gain or loss that has been included in accumulated other comprehensive income at the time the hedge is discontinued continues to be deferred in accumulated other comprehensive income until the original hedged transaction is recognized in earnings. If the likelihood of the original hedged transaction occurring is no longer probable, the entire gain or loss in accumulated other comprehensive income related to this transaction is immediately reclassified to earnings.

Consolidated Financial Statements INTEROIL CORPORATION 15

InterOil Corporation

Notes to Consolidated Financial Statements

(Expressed in United States dollars)

Significant accounting policies (cont’d)

The Company discontinues hedge accounting prospectively when it is determined that the derivative is no longer effective in offsetting changes in cash flows of the hedged item, the derivative expires or is sold, terminated or exercised, the derivative is no longer designated as a hedging instrument because it is unlikely that a forecasted transaction will occur, a hedged firm commitment no longer meets the definition of a firm commitment or management determines that designation of the derivative as a hedging instrument is no longer appropriate.

(iv) Compound financial instruments

Compound financial instruments issued by the Company comprise convertible notes that can be converted to share capital at the option of the holder, when the number of shares to be issued does not vary with changes in their fair value. The liability component of a compound financial instrument is recognized initially at fair value of a similar liability that does not have an equity conversion option. The equity component is recognized initially at the difference between the fair value of the compound financial instrument as a whole and the fair value of the liability component. Any directly attributable transaction costs are allocated to the liability and equity components in proportion to their initial carrying amounts.

Subsequent to initial recognition, the liability component of a compound financial instrument is measured at amortized cost using the effective interest method. The equity component of a compound financial instrument is not re-measured subsequent to initial recognition. Interest and losses and gains relating to the financial liability are recognized in profit or loss. On conversion, the financial liability is reclassified to equity and no gain or loss is recognized on conversion.

(i)

Cash and cash equivalents

Cash and cash equivalents includes cash on hand, deposits held at call with financial institutions, other short-term, highly liquid investments with original maturities of three months or less that are readily convertible to known amounts of cash and which are subject to insignificant risk of changes in value.

(j)

Cash restricted

Cash restricted consists of cash on deposit which is restricted from being used in daily operations. Cash restricted is carried at cost and any accrued interest is classified under other assets.

(k)

Deferred financing costs

Deferred financing costs represent the unamortized financing costs paid to secure borrowings. Amortization is provided on an effective yield basis over the term of the related debt and is included in expenses for the period. Unamortized deferred financing costs are offset against the respective liability accounts.

(l)

Plant and equipment

Property, plant and equipment are recorded at amortized cost. Depreciation of assets begins when the asset is in place and ready for its intended use. Assets under construction and deferred project costs are not depreciated. Depreciation of plant and equipment is calculated using the straight line method, based on the estimated service life of the asset. Maintenance and repair costs are expensed as incurred. Improvements that increase the capacity or prolong the service life of an asset are capitalized.

Please refer to note 4 for details of plant and equipment related to the discontinued operations.

Land is not depreciated. Depreciation on other assets is calculated using the straight-line method to allocate their cost or revalued amounts, net of their residual values, over their estimated useful lives as follows:

Leasehold land improvements	Shorter of 100 years or lease period
Refinery	4 – 25 years
Buildings	20 – 40 years
Plant and equipment	3 – 15 years
Motor vehicles	4 – 5 years

Consolidated Financial Statements INTEROIL CORPORATION 16

InterOil Corporation

Notes to Consolidated Financial Statements

(Expressed in United States dollars)

Significant accounting policies (cont’d)

Leased assets (accounting as lessee): Leases of property, plant and equipment where the Company has substantially all the risks and rewards of ownership are classified as finance leases. Finance leases are capitalized at the inception of the lease at the lower of the fair value of the leased property and the present value of the minimum lease payments. The corresponding rental obligations, net of finance charges, are included in other long term payables. Each lease payment is allocated between the liability and the finance charges so as to achieve a constant rate on the finance balance outstanding. The interest element of the finance cost is charged to the comprehensive income statement over the lease period so as to produce a constant periodic rate of interest on the remaining balance of the liability for each period. The property, plant and equipment acquired under finance leases are depreciated over the shorter of the asset’s useful life and the lease term.

Leases in which a significant portion of the risks and rewards of ownership are retained by the lessor are classified as operating leases. Operating lease payments are representative of the pattern of benefit derived from the leased asset and accordingly are included in expenses on a straight line basis over the period of the lease.

Leased assets (accounting as lessor): Assets are leased out under an operating lease. The asset is included in the balance sheet based on the nature of the asset. Lease income is recognized over the term of the lease on a straight-line basis.

Asset retirement obligations: A liability is recognized for future legal or constructive retirement obligations associated with the Company’s property, plant and equipment. The amount recognized is the net present value of the estimated costs of future dismantlement, site restoration and abandonment of properties based upon current regulations and economic circumstances at period end.

Following the sale of the refining and distribution businesses on June 30, 2014, the Company no longer has a provision for asset retirement obligations.

Environmental remediation: Remediation costs are accrued based on best estimates of known environmental remediation exposure. Ongoing environmental compliance costs, including maintenance and monitoring costs, are expensed as incurred. Provisions are determined on an assessment of current costs, current legal requirements and current technology. Changes in estimates are dealt with on a prospective basis. In relation to the Company’s exploration and development operations, the Company’s activities are still largely in the exploration and appraisal phase. As there are no production wells, there is minimal rectification required of the footprint created by the activities at this stage. In addition, these operations are carried out in remote jungle areas within PNG, and the minimal footprint currently in existence would be rapidly eliminated with the regrowth of the jungle.

Disposal of property, plant and equipment: At the time of disposal of plant and equipment, the carrying values of the assets are written off along with accumulated depreciation and any resulting gain or loss is included in the income statement. Gains and losses on disposals are determined by comparing proceeds with carrying amounts.

IT Development and software: Costs incurred in development products or systems and costs incurred in acquiring software and licenses that will contribute to future period financial benefits through revenue generation and/or cost reduction are capitalized. Costs capitalized include external direct costs of materials and service, direct payroll and payroll related costs of employees’ time spent on the project. Amortization is calculated on a straight line basis over periods generally ranging from 3 to 5 years. IT development costs include only those costs directly attributable to the development phase and are only recognized following completion of technical feasibility and where the Company has an intention and ability to use the asset. These amounts are capitalized as part of property, plant and equipment.

(m)

Exploration and evaluation assets

The Company uses the successful-efforts method to account for its oil and gas exploration and development activities. Under this method, costs are accumulated on a field-by-field basis with certain exploratory expenditures and exploratory dry holes being expensed as incurred. The Company continues to carry as an asset the cost of drilling exploratory wells if the required capital expenditure is made and drilling of additional exploratory wells is underway or firmly planned for the near future or when exploration and evaluation activities have not yet reached a stage to allow reasonable assessment regarding the existence of economic reserves. Capitalized costs for producing wells will be subject to depletion using the units-of-production method.

Geological and geophysical costs are expensed as incurred, except when they have been incurred to facilitate production techniques, to increase total recoverability and to determine the desirability of drilling additional development wells within an area in which there has been a discovery of resources. Geological and geophysical costs capitalized would be included as part of the cost of producing wells and be subject to depletion using the units-of-production method.

Consolidated Financial Statements INTEROIL CORPORATION 17

InterOil Corporation

Notes to Consolidated Financial Statements

(Expressed in United States dollars)

Significant accounting policies (cont’d)

Farm-in

The Company capitalizes all expenditures that are incurred for acquisition of rights to explore, carry costs on behalf of the seller to acquire an interest in the asset, or any other activity in relation to evaluating technical feasibility and commercial viability of an interest farmed into.

Farm-outs

Conveyances of mineral interests in properties may involve the transfer of all or a part of the rights and responsibilities of operating a property, or sufficient risks and benefits of ownership to the transferee. Conveyance accounting is triggered by the Company on the sale of a property, where applying judgment to the facts presented, it concludes that sufficient risks and benefits of ownership has passed to the transferee.

If a part of the interest in an unproved property is sold, the amount received shall be treated as a recovery of cost. If the sales price exceeds the carrying amount of a property, a gain shall be recognized in the amount of such excess.

The sale of a part of a proved property, or of an entire proved property, shall be accounted for as the sale of an asset, and a gain or loss shall be recognized. The unamortized cost of the property or group of properties, a part of which was sold, shall be apportioned to the interest sold and the interest retained on the basis of the fair values of those interests.

In the following types of conveyances, a gain shall not be recognized at the time of the conveyance:

A part of an interest owned is sold and substantial uncertainty exists about recovery of the costs applicable to the retained interest.

A part of an interest owned is sold and the Company has a substantial obligation for future performance, such as an obligation to drill a well or to operate the property without proportional reimbursement for that portion of the drilling or operating costs applicable to the interest sold.

(n)

Impairment

Non-derivative financial assets: A financial asset not carried at fair value through profit or loss is assessed at each reporting date to determine whether there is any objective evidence that it is impaired. A financial asset is considered to be impaired if objective evidence indicates that one or more events have had a negative effect on the estimated future cash flows of that asset.

An impairment loss in respect of a financial asset measured at amortized cost is calculated as the difference between its carrying amount, and the present value of the estimated future cash flows discounted at the original effective interest rate. An impairment loss in respect of an available-for-sale financial asset is calculated by reference to its fair value. Individually significant financial assets are tested for impairment on an individual basis. The remaining financial assets are assessed collectively in groups that share similar credit risk characteristics.

All impairment losses are recognized in the consolidated income statement. An impairment loss, other than relating to available-for-sale equity instruments, is reversed through profit and loss if the reversal can be related objectively to an event occurring after the impairment loss was recognized. The reversal of an impairment loss relating to available-for-sale equity instruments is through other comprehensive income.

Trade and other receivables

The collectability of trade and other receivables is assessed on an ongoing basis. Debts which are known to be uncollectible are written off by reducing the carrying amount directly. An allowance account (provision for impairment of trade receivables) is used when there is objective evidence that the company will not be able to collect all amounts due according to the original terms of the receivables. Significant financial difficulties of the debtor, probability that the debtor will enter bankruptcy or financial reorganization, and default or delinquency in payments are considered indicators that the receivable is impaired. The amount of the impairment allowance is the difference between the asset’s carrying amount and the present value of estimated future cash flows, discounted at the original effective interest rate. Cash flows relating to short-term receivables are not discounted if the effect of discounting is immaterial.

The amount of the impairment loss is recognized in the income statement. When a trade or other receivable for which an impairment allowance had been recognized becomes uncollectible in a subsequent period, it is written off against the allowance account. Subsequent recoveries of amounts previously written off are credited against the income statement.

Consolidated Financial Statements INTEROIL CORPORATION 18

InterOil Corporation

Notes to Consolidated Financial Statements

(Expressed in United States dollars)

Significant accounting policies (cont’d)

Prior to the sale of the refining and distribution businesses , the Company discounted certain trade receivables to BNP Paribas Capital (Singapore) Limited (“BNP Paribas”) under its $80.0 million bilateral non-recourse discounting facility, and certain receivables under the syndicated secured refinery working capital facility which included the ability to discount receivables with recourse up to $30.0 million. The non-recourse discounted receivables were not retained on the Company’s balance sheet, while with-recourse discounted receivables were retained on the balance sheet as the Company retained the credit risk and control over these receivables.

Non-financial assets: The carrying amounts of the Company’s non-financial assets, other than inventories and deferred tax assets are reviewed at each reporting date to determine whether there is any indication of impairment. If any such indication exists then the asset’s recoverable amount is estimated. For goodwill, and intangible assets that have indefinite useful lives or that are not yet available for use, the recoverable amount is estimated each period at the same time.

The recoverable amount of an asset is the greater of its value in use or its fair value less costs to sell and is determined for an individual asset, unless the asset does not generate cash inflows that are largely independent of those from other assets or groups of assets. In that situation, the assets are tested as part of a cash-generating unit (“CGU”), which is the smallest identifiable group of assets, liabilities and associated goodwill that generates cash inflows that are largely independent of the cash inflows from other assets or groups of assets.

Fair value is the amount of the consideration that would be agreed upon in an arm's length transaction between knowledgeable, willing parties who are under no compulsion to act. Value in use is determined as the net present value of the estimated future cash flows expected to arise from the continued use of the asset in its present form and its eventual disposal, discounted at the risk free rate of interest plus a risk premium. If an impairment loss is recognized, the adjusted carrying amount becomes the new cost basis.

An impairment loss is recognized if the carrying amount of an asset or its CGU exceeds its recoverable amount. Impairment losses recognized in respect of CGUs are allocated first to reduce the carrying amount of any goodwill allocated to the CGU and then to reduce the carrying amounts of the other assets in the CGU on a pro rata basis. Impairment losses are recognized in profit or loss.

Impairment losses recognized in prior periods are assessed at each reporting date for any indications that the loss has decreased or no longer exists. An impairment loss is reversed if there has been a change in the estimates used to determine the recoverable amount. An impairment loss is reversed only to the extent that the asset’s carrying amount does not exceed the carrying amount that would have been determined, net of depreciation or amortization, if no impairment loss had been recognized.

There has been no impairment of assets based on the assessments performed during the period.

(o)

Revenue recognition

Revenue is measured at the fair value of the consideration received or receivable. Amounts disclosed as revenue are net of returns, trade allowances and duties and taxes paid. The following particular accounting policies, which significantly affect the measurement of results, have been applied.

Other Revenue: Revenue from logistics, rig and constructions services are recognized in the accounting period in which the services are rendered. As of July 1, 2014, the Company ceased to operate a shared services model that resulted in the recognition of other revenue from the internal support of the exploration and development activities. These costs have been since been allocated to those activities as a recovery of cost, rather than as other revenue. The Company is also moving to more outsourced services model with leasing third party rigs and services rather than internally servicing the exploration and development operations.

Interest revenue: Interest revenue is recognized as the interest accrues using the effective interest rate.

(p)

Income tax

Income tax comprises current and deferred tax. Income tax is recognized in the income statement except to the extent that it relates to items recognized directly in other comprehensive income or directly in equity, in which case the income tax is also recognized directly in other comprehensive income or equity respectively. The income tax expense or benefit for the period is the tax payable on the current period’s taxable income based on the national income tax rate for each jurisdiction; adjusted by changes in deferred tax assets and liabilities attributable to temporary differences between the tax bases of assets and liabilities and their carrying amounts in the financial statements and to unused tax losses. Management periodically evaluates positions taken in tax returns with respect to situations in which applicable tax regulation is subject to interpretation.

Consolidated Financial Statements INTEROIL CORPORATION 19

InterOil Corporation

Notes to Consolidated Financial Statements

(Expressed in United States dollars)

Significant accounting policies (cont’d)

Deferred tax assets and liabilities are recognized for temporary differences at the tax rates expected to apply when the assets are recovered or liabilities are settled, based on those tax rates which are enacted or substantively enacted for each jurisdiction. The relevant tax rates are applied to the cumulative amounts of deductible and taxable temporary differences to measure the deferred tax asset or liability. Deferred income tax assets and liabilities are presented as non-current. Deferred tax assets and liabilities are offset when there is a legally enforceable right to offset current tax assets and liabilities and when the deferred tax balances relate to the same taxation authority. Current tax assets and tax liabilities are offset where the entity has a legally enforceable right to offset and intends either to settle on a net basis, or to realize the asset and settle the liability simultaneously.

Deferred tax assets are recognized for deductible temporary differences and unused tax losses only if it is probable that future taxable amounts will be available to utilize those temporary differences and losses. Deferred tax assets are reviewed at each reporting date and are reduced to the extent that it is no longer probable that the related tax benefit will be realized. In addition to income taxes, InterOil is subject to Goods and Services Tax, Excise Duty and other taxes in PNG, Australia, Singapore and Canada. The consolidated financial statements are prepared on a net of Goods and Services Tax basis.

(q)

Employee entitlements

Wages and salaries, and annual leave: Liabilities for wages and salaries, including annual leave expected to be settled within 12 months of the reporting date are recognized in accounts payable and accrued liabilities in respect of employees’ services up to the reporting date and are measured at the amounts expected to be paid when liabilities are settled.

Long service leave: The liability for long service leave is recognized in the provision for employee benefits and measured as the present value of expected future payments to be made in respect of services provided by employees up to the reporting date. Consideration is given to expected future wage and salary levels, experience of employee departures, periods of service and statutory obligations.

Post-employment obligations: The Company contributed to a defined contribution plan and the Company’s legal or constructive obligation is limited to these contributions. Contributions to the defined contribution fund are recognized as an expense as they become payable.

Share-based payments: Stock-based compensation benefits are provided to employees and directors pursuant to the 2009 Stock Incentive Plan (with options still in existence having been granted under the now superseded 2006 Stock Incentive Plan). The Company currently issues stock options and restricted stock units as part of its stock-based compensation plan. The fair value of stock options at grant date is determined using a Black-Scholes option pricing model that takes into account the exercise price, the terms of the option, the vesting criteria, the share price at grant date and expected price volatility of the underlying share, the expected yield and risk-free interest rate for the term of the option. The Company has not used a forfeiture rate as the assumption is for a 100% vesting of the granted options, however, if the options are forfeited prior to vesting, then any amounts expensed in relation to those forfeited shares are reversed. Upon exercise of options, the balance of the contributed surplus relating to those options is transferred to share capital. The fair value of restricted stock units on grant date is the market value of the stock.

The Company uses the fair value based method to account for employee stock based compensation benefits. Under the fair value based method, compensation expense is measured at fair value at the date of grant and is expensed over the award's vesting period.

Profit-sharing and bonus plans: The Company recognizes a provision where contractually obliged or where there is a past practice that has created a constructive obligation.

(r)

Earnings per share

Basic earnings per share: Basic common shares outstanding are the weighted average number of common shares outstanding for each period. Basic earnings per share is calculated by dividing the profit or loss attributable to shareholders of the Company by the weighted average number of common shares outstanding during the period.

Diluted earnings per share: Diluted earnings per share is determined by adjusting the profit or loss attributable to shareholders and the weighted average number of common shares outstanding, for the effects of all dilutive potential ordinary shares, which comprise convertible notes and share options granted to employees.

The earnings per share derived from continuing operations and discontinuing operations have been separately disclosed in the consolidated income statement, following the classification defined in note 1.

Consolidated Financial Statements INTEROIL CORPORATION 20

InterOil Corporation

Notes to Consolidated Financial Statements

(Expressed in United States dollars)

Financial Risk Management

The Company’s activities expose it to a variety of financial risks; market risk, credit risk, liquidity risk and geographic risk. The Company’s overall risk management program focuses on the unpredictability of markets and seeks to minimize potential adverse effects on the financial performance of the Company.

Risk Management is carried out under policies approved by the board of directors of InterOil. The Finance Department identifies, evaluates and actively mitigates financial risks in close cooperation with the Company’s operations. The board of directors of InterOil provides written principles for overall risk management, as well as written policies covering specific areas. The Company’s overall risk management program seeks to minimize potential adverse effects on the Company’s financial performance.

(a)

Market risk

(i) Foreign exchange risk

Foreign exchange risk arises when future commercial transactions and recognized assets and liabilities are denominated in a currency that is not the Company’s functional currency. The Company operates internationally and is exposed to foreign exchange risk arising from currency exposures to the USD. The consolidated financial statements are presented in USD which is the Company’s functional and presentation currency. Most of the Company’s transactions are undertaken in USD, PNG Kina (“PGK”), Australian Dollars (“AUD”) and Singapore Dollars (“SGD”).

The PGK weakened against the USD during the year ended December 31, 2014 (from 0.4130 to 0.3855) and also weakened during the year ended December 31, 2013 (from 0.4755 to 0.4130), but strengthened slightly during the year ended December 31, 2012 (from 0.4665 to 0.4755).

The financial instruments denominated in PGK and translated to USD as at December 31, 2014 are as follows:

	December 31,		December 31,		December 31,
	2014		2013		2012
	$		$		$
Financial assets
Cash and cash equivalents		6,869,370		11,104,619		32,422,704
Cash restricted		178,155		147,372		167,329
Receivables		641,600		73,619,243		61,493,200
Other financial assets		535,579		8,906,335		3,083,655

Financial liabilities
Payables		14,455,532		25,839,942		30,033,391
Working capital facility		-		12,437,780		-
Secured loans		-		24,780,077		-

The following table summarizes the sensitivity of financial instruments held at balance sheet date to movement in the exchange rate of the USD to the PGK, with all other variables held constant. Certain USD debt and other financial assets and liabilities are not held in the functional currency of the relevant subsidiary. This results in an accounting exposure to exchange gains and losses as the financial assets and liabilities are translated into the functional currency of the subsidiary that accounts for those assets and liabilities. These exchange gains and losses are recorded in the consolidated income statement except to the extent that they can be taken to equity under the Company’s accounting policy. If PGK appreciates/(depreciates) by 5% against the USD, it will result in a gain/(loss) as per the table below.

	Year ended					Year ended				Year ended
	December 31, 2014					December 31, 2013				December 31, 2012
	Impact on profit			Impact on equity - excluding profit impact		Impact on profit		Impact on equity - excluding profit impact		Impact on profit		Impact on equity - excluding profit impact
	$			$		$		$		$		$

Post-tax gain/(loss)
Effect of 5% appreciation of PGK		(311,541	)		-		565,725		970,263		2,079,351		1,279,796

Consolidated Financial Statements INTEROIL CORPORATION 21

InterOil Corporation

Notes to Consolidated Financial Statements

(Expressed in United States dollars)

Financial Risk Management (cont’d)

The changes in AUD and SGD to USD exchange rate can also affect the Company’s results as the expenses of the corporate offices in Australia (prior to its closure) and Singapore are incurred in the respective local currencies. The AUD and SGD exposures are minimal currently as funds are transferred to AUD and SGD from USD as required. No material balances are held in AUD or SGD. However, the Company is exposed to translation risks resulting from AUD and SGD fluctuations as in country costs are being incurred in AUD and SGD, and reporting for those costs being in USD.

(ii) Price risk

Following the disposal of the Company’s refining and distribution businesses, the Company had no exposure to product price risk.

(iii) Interest rate risk

Interest rate risk is the risk that the Company’s financial position will be adversely affected by movements in interest rates that will increase the cost of floating rate debt or opportunity losses that may arise on fixed rate borrowings in a falling interest rate environment. As the Company has no significant interest-bearing assets other than cash and cash equivalents, the Company’s income and operating cash flows are substantially independent of changes in market interest rates.

The Company’s interest-rate risk arises from cash and cash equivalent balances, borrowings and working capital financing facilities. Deposits/borrowings at variable rates expose the Company to cash flow interest-rate risk. Deposits/borrowings at fixed rates expose the Company to fair value interest-rate risk. The Company is actively seeking to manage its cash flow interest-rate risks by holding some cash, cash equivalents and borrowings in fixed rate instruments and others in variable rate instruments.

The financial instruments exposed to cash flow and fair value interest rate risk are as follows:

	December 31, 2014		December 31, 2013		December 31, 2012		Cash flow/fair value
	$		$		$		interest rate risk
Financial assets
Cash and cash equivalents		332,332,007		30,228,099		259,584	fair value interest rate risk
Cash and cash equivalents		61,073,191		31,738,440		49,461,096	cash flow interest rate risk
Cash restricted		8,301,133		324,818		374,755	fair value interest rate risk
Cash restricted		-		52,889,726		48,636,339	cash flow interest rate risk
Financial liabilities
ANZ, BSP & BNP syndicated secured loan		-		84,000,000		100,000,000	cash flow interest rate risk
Westpac secured loan		-		-		12,857,000	cash flow interest rate risk
BSP & Westpac secured facility		-		24,780,077		-	cash flow interest rate risk
Credit Suisse secured loan		-		100,000,000		-	cash flow interest rate risk
Mitsui unsecured loan		-		-		11,912,297	cash flow interest rate risk
BNP working capital facility		-		23,941,251		94,290,479	cash flow interest rate risk
Westpac working capital facility		-		9,793,577		-	cash flow interest rate risk
BSP working capital facility		-		2,644,203		-	cash flow interest rate risk
2.75% convertible notes		69,998,000		69,998,000		70,000,000	fair value interest rate risk

The following table summarizes the sensitivity of the cash flow interest-rate risk of financial instruments held at balance date, following a movement in LIBOR, with all other variables held constant. Increase in LIBOR rates will result in a lower net loss for the Company where the Company has net financial assets exposed to cash flow interest-rate risk, as is the case at December 31, 2014, or will result in a higher net loss for the Company where the Company has net financial liabilities exposed to cash flow interest-rate risk, as is the case at December 31, 2013 and December 31, 2012.

Consolidated Financial Statements INTEROIL CORPORATION 22

InterOil Corporation

Notes to Consolidated Financial Statements

(Expressed in United States dollars)

Financial Risk Management (cont’d)

	Year ended					Year ended				Year ended
	December 31, 2014					December 31, 2013				December 31, 2012
	Impact on profit			Impact on equity - excluding profit impact		Impact on profit		Impact on equity - excluding profit impact		Impact on profit		Impact on equity - excluding profit impact
	$			$		$		$		$		$

Post-tax loss/(gain)
LIBOR Increase by 1%		(2,360,839	)		-		1,654,428		-		821,268		-

(b)

Liquidity risk

Liquidity risk is the risk that InterOil will not meet its financial obligations as they fall due. Prudent liquidity risk management therefore implies that, under both normal and stressed conditions, the Company maintains:

sufficient cash and marketable securities;

access to, or availability of, funding through an adequate amount of committed credit facilities; and

the ability to close-out any open market positions.

The Company manages liquidity risk by continuously monitoring forecast and actual cash flows; matching maturity profiles of financial assets and liabilities; and by maintaining flexibility in funding including ensuring that surplus funds are generally only invested in instruments that are tradable in highly liquid markets or that can be relinquished with minimal risk of loss.

Refer to note 2(b) for further discussion of the Company’s current liquidity.

(i) Financing arrangements

The Company had the following borrowing facilities at the reporting date:

			Undrawn Amount
	Total Facility		December 31, 2014
	$		$
Facility
Credit Suisse secured loan		300,000,000		300,000,000
2.75% convertible notes		69,998,000		-
		369,998,000		300,000,000

(ii) Maturities of financial liabilities

The tables below analyses the Company’s financial liabilities, net and gross settled derivative financial instruments into relevant maturity groupings based on the remaining period at the reporting date to the contractual maturity date. The amounts disclosed in the table are the contractual undiscounted cash flows.

	Less than 1 year		Between 1 and 5 years		More than 5 years		Total contractual cash flow
Non-derivatives
Trade and other payables (note 12)		139,716,105		-		-		139,716,105
2.75% convertible notes (note 17)*		71,763,000		-		-		71,763,000
Other financial liabilities (note 15)		-		96,000,000		-		96,000,000
Total non-derivatives		211,479,105		96,000,000		-		307,479,105

Total derivatives		-		-		-		-
		211,479,105		96,000,000		-		307,479,105

*The balance comprises of the convertible notes principal and interest payments forecasted.

Consolidated Financial Statements INTEROIL CORPORATION 23

InterOil Corporation

Notes to Consolidated Financial Statements

(Expressed in United States dollars)

Financial Risk Management (cont’d)

The ageing of trade and other payables are as follows:

			Payable ageing between
Trade and other payables	Total		<30 days		30-60 days		>60 days
	$		$		$		$
December 31, 2014		139,716,105		134,556,055		1,528,699		3,631,351
December 31, 2013		134,027,347		131,087,614		604,294		2,335,439
December 31, 2012		178,313,483		171,197,387		3,746,493		3,369,603

(c) Credit risk

Credit risk is the risk that a contracting entity will not complete its obligation under a financial instrument that will result in a financial loss to the Company. The carrying amount of financial assets represents the maximum credit exposure.

The Company’s credit risk is limited to the carrying value of its financial assets. Credit risk on cash and cash equivalents held directly by the Company are minimized as all cash amounts and certificates of deposit are held with banks which have acceptable credit ratings. Credit risk on trade and other receivables at December 31, 2014 are also minimized as these represent receivables from joint venture partners where the risk of default is minimal as it would impact the partners’ interest in the Company’s relevant exploration and development assets.

The maximum exposure to credit risk at the reporting date was as follows:

	December 31,		December 31,		December 31,
	2014		2013		2012
	$		$		$
Current
Cash and cash equivalents		393,405,198		61,966,539		49,720,680
Cash restricted		7,959,859		36,149,544		37,340,631
Trade and other receivables
- Trade and other receivables		21,207,984		98,638,110		161,578,481
- Sale proceeds receivable from Total S.A.		545,154,761		-		-
Commodity derivative contracts		-		-		233,922
Non-current
Cash restricted		341,274		17,065,000		11,670,463
Other non-current receivables		29,700,534		29,700,534		5,000,000

The ageing of trade and other receivables at the reporting date was as follows (the ageing days relates to balances past due):

			Receivable ageing
Net trade and other receivables	Total		Current		<30 days		30-60 days		>60 days
	$		$		$		$		$
December 31, 2014		21,207,984		19,114,646		304,438		77,448		1,711,452
December 31, 2013		98,638,110		62,410,658		23,973,075		4,113,546		8,140,831
December 31, 2012		161,578,481		110,557,921		36,955,969		12,134,466		1,930,125

The impairment of trade and other receivables at the reporting date was as follows:

					Overdue		Overdue
Gross trade and other receivables	Total		Current		(not impaired)		(impaired)
	$		$		$		$
December 31, 2014		22,916,065		19,114,646		2,093,339		1,708,080
December 31, 2013		98,827,500		62,410,658		36,227,452		189,390
December 31, 2012		161,818,882		110,557,921		51,020,560		240,401

Impairment is assessed by the Company on an individual joint venture partner basis, based on payment histories of the joint venture partner. An impairment provision is taken for all receivables where objective evidence of impairment exists. The credit quality of financial assets that are neither past due nor impaired can be assess by reference to external credit ratings (if available). Total S.A. has a current credit rating of AA- as assessed by Standard & Poor.

Consolidated Financial Statements INTEROIL CORPORATION 24

InterOil Corporation

Notes to Consolidated Financial Statements

(Expressed in United States dollars)

Financial Risk Management (cont’d)

The movement in impaired trade and other receivables for the year ended December 31, 2014 was as follows:

				Year ended
	December 31, 2014			December 31, 2013			December 31, 2012
	$			$			$

Trade receivables - Impairment provisions
Opening balance		189,390			240,401			1,522,145
Foreign exchange impact on opening balance		(459	)		(31,598	)		29,366
Amounts written off during the period		(126,773	)		(378,662	)		(1,277,913	)
Transfer of impaired receivables upon disposal of subsidiary		(335,541	)		-			-
Movement in provisions, net of reversals made		1,981,463			359,249			(33,197	)
Closing balance		1,708,080			189,390			240,401

(d)

Geographic risk

The operations of InterOil are concentrated in PNG.

(e)

Financing facilities

As at December 31, 2014, the Company had only drawn down against the 2.75% convertible notes financing facility. Repayment obligations in respect of the amount of the facility utilized are as follows:

	December 31,		December 31,		December 31,
	2014		2013		2012
	$		$		$
Due:
No later than one year		69,998,000		177,159,108		126,488,776
Later than one year but not later than two years		-		89,998,000		20,286,000
Later than two years but not later than three years		-		24,000,000		94,286,000
Later than three years but not later than four years		-		24,000,000		24,000,000
Later than four years but not later than five years		-		-		24,000,000
Later than five years		-		-		-
		69,998,000		315,157,108		289,060,776

(f)

Effective interest rates and maturity profile

	Floating		Fixed interest maturing between																Effective
	interest		1 year		1-2		2-3		3-4		4-5		more than		Non-interest				interest
	rate		or less										5 years		bearing		Total		rate
December 31, 2014	$		$		$		$		$		$		$		$		$		%

Financial assets
Cash and cash equivalents		61,073,191		332,332,007		-		-		-		-		-		-		393,405,198		0.17	%
Cash restricted		-		8,301,133		-		-		-		-		-		-		8,301,133		0.05	%
Receivables:
- Trade and other receivables		-		-		-		-		-		-		-		50,908,518		50,908,518		-
- Sale proceeds receivable from Total S.A.				545,154,761		-		-		-		-		-		-		545,154,761		7.97	%
Other financial assets		-		-		-		-		-		-		-		2,312,626		2,312,626		-
		61,073,191		885,787,901		-		-		-		-		-		53,221,144		1,000,082,236
Financial liabilities
Payables		-		-		-		-		-		-		-		141,525,847		141,525,847		-
Convertible notes liability		-		69,998,000		-		-		-		-		-		-		69,998,000		7.91	%
Other financial liabilities		-		-		-		-		-		-		-		162,501,994		162,501,994		-
		-		69,998,000		-		-		-		-		-		304,027,841		374,025,841

Consolidated Financial Statements INTEROIL CORPORATION 25

InterOil Corporation

Notes to Consolidated Financial Statements

(Expressed in United States dollars)

Financial Risk Management (cont’d)

	Floating		Fixed interest maturing between																Effective
	interest		1 year		1-2		2-3		3-4		4-5		more than		Non-interest				interest
	rate		or less										5 years		bearing		Total		rate
December 31, 2013	$		$		$		$		$		$		$		$		$		%

Financial assets
Cash and cash equivalents		31,738,440		30,228,099		-		-		-		-		-		-		61,966,539		0.08	%
Cash restricted		52,889,726		324,818		-		-		-		-		-		-		53,214,544		2.56	%
Receivables		-		-		-		-		-		-		-		128,338,644		128,338,644		-
Other financial assets		-		-		-		-		-		-		-		8,125,270		8,125,270		-
		84,628,166		30,552,917		-		-		-		-		-		136,463,914		251,644,997
Financial liabilities
Payables		-		-		-		-		-		-		-		151,115,321		151,115,321		-
Interest bearing liabilities		245,159,108		-		-		-		-		-		-		-		245,159,108		11.54	%
Convertible notes liability		-		-		69,998,000		-		-		-		-		-		69,998,000		7.91	%
Other financial liabilities		-		-		-		-		-		-		-		97,869,253		97,869,253		-
		245,159,108		-		69,998,000		-		-		-		-		248,984,574		564,141,682

	Floating		Fixed interest maturing between																Effective
	interest		1 year		1-2		2-3		3-4		4-5		more than		Non-interest				interest
	rate		or less										5 years		bearing		Total		rate
December 31, 2012	$		$		$		$		$		$		$		$		$		%

Financial assets
Cash and cash equivalents		49,600,460		259,584		-		-		-		-		-		-		49,860,044		0.14	%
Cash restricted		48,629,998		381,096		-		-		-		-		-		-		49,011,094		2.68	%
Receivables		-		-		-		-		-		-		-		151,948,227		151,948,227		-
Investments		-		-		-		-		-		-		-		4,304,176		4,304,176		-
Other financial assets		-		-		-		-		-		-		-		8,751,262		8,751,262		-
		98,230,458		640,680		-		-		-		-		-		165,003,665		263,874,803
Financial liabilities
Payables		-		-		-		-		-		-		-		192,004,062		192,004,062		-
Interest bearing liabilities		219,059,776		-		-		-		-		-		-		-		219,059,776		6.64	%
Convertible notes liability		-		-		-		70,000,000		-		-		-		-		70,000,000		7.91	%
Other financial liabilities		-		-		-		-		-		-		-		20,961,380		20,961,380		-
		219,059,776		-		-		70,000,000		-		-		-		212,965,442		502,025,218

Consolidated Financial Statements INTEROIL CORPORATION 26

InterOil Corporation

Notes to Consolidated Financial Statements

(Expressed in United States dollars)

Financial Risk Management (cont’d)

(g)

Fair values

	December 31, 2014				December 31, 2013						December 31, 2012				Fair value
	Carrying amount		Fair value		Carrying amount			Fair value			Carrying amount		Fair value		hierarchy level	Method of
	$		$		$			$			$		$		(as required) *	measurement
Financial instruments
Financial assets
Loans and receivables
Cash and cash equivalents		393,405,198		393,405,198		61,966,539			61,966,539			49,720,680		49,720,680		Amortized Cost
Cash restricted		8,301,133		8,301,133		53,214,544			53,214,544			49,011,094		49,011,094		Amortized Cost
Receivables		566,362,745		566,362,745		98,638,110			98,638,110			161,578,481		161,578,481		Amortized Cost
Other non-current receivable		29,700,534		29,700,534		29,700,534			29,700,534			5,000,000		5,000,000		Amortized Cost
Available-for-sale
Investments		-		-		-			-			4,304,176		4,304,176	Level 1	Fair Value - See (i) below
Held for trading
Derivative contracts		-		-		(1,869,253	)		(1,869,253	)		233,922		233,922	Level 2	Fair Value - See (ii) below
Financial liabilities
Current liabilities:
Accounts payable and accrued liabilities		139,716,105		139,716,105		134,027,347			134,027,347			178,313,483		178,313,483		Amortized Cost
Working capital facilities		-		-		36,379,031			36,379,031			94,290,479		94,290,479		Amortized Cost
2.75% Convertible notes liability		66,501,994		66,501,994		-			-			-		-		Amortized Cost
Unsecured loans and current portion of secured loans		-		-		134,775,077			134,775,077			31,383,115		31,383,115		Amortized cost See (iii) below
Non-current liabilities
Secured loans		-		-		65,681,425			65,681,425			89,446,137		89,446,137		Amortized cost See (iii) below
2.75% Convertible notes liability		-		-		62,662,628			62,662,628			59,046,581		59,046,581		Amortized Cost
Other non-current liabilities		96,000,000		96,000,000		96,000,000			96,000,000			20,961,380		20,961,380		Amortized Cost

* Where fair value of financial assets or liabilities is approximated by its carrying value, designation under the fair value hierarchy is not required.

The net fair value of cash and cash equivalents and non-interest bearing financial assets and financial liabilities of the Company approximates their carrying amounts.

The carrying values (less impairment provision if provided) of trade receivables and payables are assumed to approximate their fair values due to their short-term nature. The carrying value of financial liabilities approximates their fair values which, for disclosure purposes, are estimated by discounting the future contractual cash flows at the current market interest rate that is available to the Company for similar financial instruments.

Commodity derivative contracts’ and available-for-sale investments are the only items from the above table that are measured at fair value on a recurring basis. All the remaining financial assets and financial liabilities are measured at a fair value on a non-recurring basis and are maintained at historical amortized cost.

The fair value of financial assets and financial liabilities must be estimated for recognition and measurement or for disclosure purposes. The Company has classified the fair value measurements using a fair value hierarchy that reflects the significance of the inputs used in making the measurements. The fair value hierarchy shall have the following levels:

Level 1 - quoted prices (unadjusted) in active markets for identical assets or liabilities

Level 2 - inputs other than quoted prices included in Level 1 that are observable for the asset or liability, either directly (i.e., as prices) or indirectly (i.e., derived from prices); and

Level 3 - inputs for the asset or liability that are not based on observable market data (unobservable inputs).

(i) Investments classified as being available-for-sale were fair valued by using quoted prices on Oslo stock exchange Axess. These investments were sold during the year ended December 31, 2013.

(ii) Derivative contracts classified as being at fair value through profit and loss are fair valued by comparing the contracted rate to the current market rate for a contract with the same remaining period to maturity. The fair value of the Company’s derivative contracts are based on price indications provided to us by an external brokerage who enter into derivative transactions with counter parties on the Company’s behalf. The contracts related to the hedging of certain product price risk exposures were transferred to Puma on completion of the sale of the Midstream Refining operation on June 30, 2014.

Consolidated Financial Statements INTEROIL CORPORATION 27

InterOil Corporation

Notes to Consolidated Financial Statements

(Expressed in United States dollars)

Financial Risk Management (cont’d)

(iii) All secured loans are subject to floating interest rates and as such the carrying values of these loans are assumed to approximate their fair values. These secured loans were repaid during the quarter ended June 30, 2014.

(h)

Capital management

The finance department of the Company is responsible for capital management. This involves the use of operating and development economic forecasting models which facilitates analysis of the Company’s financial position including cash flow forecasts to determine the future capital management strategy. Capital management is undertaken to ensure a secure, cost-effective and flexible supply of funds is available to meet the Company’s expenditure requirements and safeguard its abilities to continue as a going concern.

The Company is actively managing the gearing levels and raising equity/debt as required for optimizing shareholder returns. The Company is managing its gearing levels by maintaining the debt-to-capital ratio (debt/(shareholders’ equity + debt)) at 50% or less. The gearing levels were 6% at December 31, 2014 (26% at December 31, 2013 and 19% at December 31, 2012). The optimum gearing levels for the Company are overseen by the board of directors of InterOil based on recommendations by Management. Recommendations are based on operating cash flows, future cash needs for development, capital market conditions, economic conditions, and will be reassessed as situations change.

Discontinued operations

We received gross proceeds of $525,589,838 from the sale. The sale required repayment of all outstanding secured loans held by the entities sold amounting to $52,877,280. In addition, the agreements contained a cash warranty that as at June 30, 2014, combined cash balances of the sale entities would not be less than $40,469,839. The combined cash balance of the entities sold at June 30, 2014 was $39,432,150, and therefore an adjustment to the sale consideration has been recognized for $1,037,689 as amount refundable to Puma. In addition, InterOil incurred $4,257,614 in transaction costs. Therefore, the net consideration attributable to the sale transaction consists of the following:

	June 30,
	2014
	$

Cash		525,589,838
Less settlement of intercompany debt		(52,877,280	)
Less amount refundable to Puma		(1,037,689	)
Less transaction costs		(4,257,614	)
Net consideration		467,417,255

The Company made a gain on sale of these subsidiaries of $49,537,443, and there is no tax payable on this gain. The gain has been calculated as follows:

Consolidated Financial Statements INTEROIL CORPORATION 28

InterOil Corporation

Notes to Consolidated Financial Statements

(Expressed in United States dollars)

Discontinued operations (cont’d)

	June 30,
	2014
	$

Net consideration		467,417,255

Assets and liabilities disposed of
Cash and cash equivalents		39,432,150
Trade and other receivables		150,375,284
Other current assets		94,289
Inventories		143,541,718
Prepaid expenses		3,547,228
Plant and equipment		230,681,616
Deferred tax assets		46,353,729
Trade and other payables		(110,338,241	)
Income tax payable		(21,190,275	)
Derivative financial instruments		(2,242,950	)
Working capital facilities		(57,234,437	)
Asset retirement obligations		(5,140,299	)
Net assets disposed of		417,879,812

Net gain on sale of subsidiaries		49,537,443

The results of operations for these sold businesses have been presented as discontinued operations in the consolidated income statements for the years ended December 31, 2014, 2013 and 2012. In addition, the shipping business which was previously included within the Corporate segment has also been classified as a discontinued operation in the consolidated income statements for the years ended December 31, 2014, 2013 and 2012, as the activities previously being carried out by the business have been transferred to Puma with the sale of the refining and distribution businesses. There has been no gain/loss incurred on transferring the activities previously undertaken by the shipping business.

The $427,985,105 proceeds from sale of subsidiaries disclosed in consolidated statement of cash flows was made up of the $467,417,255 net consideration from the sale of subsidiaries and reduced by the $39,432,150 cash and cash equivalents disposed of, as presented in the table above. In addition, the settlement of intercompany debt of $52,877,280 has been included in the ‘increase in trade and other payables’ balance within the ‘Net cash (used in)/generated from operating activities’ of the consolidated stamen of cash flows.

Cash flows from these discontinued operations have been combined with the cash flows from continuing operations in the consolidated statements of cash flows for the years ended December 31, 2014, 2013 and 2012. Cash flows generated from/(used in) the discontinued operations are presented in the following table.

	Year ended
	December 31,			December 31,			December 31,
	2014			2013			2012
	$			$			$

Net cash generated from/(used in) operating activities		41,322,900			79,569,461			(6,413,111	)
Net cash generated from/(used in) investing activities (including an inflow of $428.0 million from the disposal of the operations)		460,556,098			(15,451,695	)		(55,718,089	)
Net cash (used in)/generated from financing activities		(48,153,553	)		(83,375,061	)		48,522,812

Total cash flows		453,725,445			(19,257,295	)		(13,608,388	)

The results of operations associated with all discontinued operations are presented in the following table.

Consolidated Financial Statements INTEROIL CORPORATION 29

InterOil Corporation

Notes to Consolidated Financial Statements

(Expressed in United States dollars)

Discontinued operations (cont’d)

	Year ended
	December 31,			December 31,			December 31,
	2014			2013			2012
	$			$			$

Revenue		696,616,015			1,398,401,191			1,310,134,384
Expenses		(666,384,534	)		(1,360,324,024	)		(1,287,075,042	)
Profit before tax from discontinued operations		30,231,481			38,077,167			23,059,342
Income tax (expense)/benefit		(7,965,955	)		(19,519,051	)		11,031,959
Profit after tax from discontinued operations		22,265,526			18,558,116			34,091,301
Gain on sale of subsidiaries		49,537,443			-			-
Profit from discontinued operations		71,802,969			18,558,116			34,091,301

Significant accounting policies applicable to the discontinued operations:

Raw materials and parts inventory: Raw materials and parts inventory were stated at the lower of cost and net realizable value. Costs comprised direct materials, direct labor and an appropriate proportion of variable and fixed overhead expenditure. Net realizable value was the estimated selling price in the ordinary course of the business less the estimated costs of completion and the estimated costs necessary to make the sale.

Crude oil and refined petroleum products: Crude oil and refined petroleum products were stated at the lower of cost and net realizable value. Crude oil and refined petroleum products were recorded on a first-in, first-out basis and the net realizable value test for crude oil and refined petroleum products were performed separately. The cost of Midstream Refining petroleum products consisted of raw material, labor, direct overheads and transportation costs. The cost of Downstream petroleum products included the cost of the product plus related freight, wharfage and insurance.

Refinery assets: Prior to the sale of the refining and distribution businesses, the Company’s most significant item of plant and equipment was the oil refinery in PNG. The refinery assets were recorded at cost less accumulated depreciation and accumulated impairment losses, if any. Refinery related assets were depreciated on straight line basis over their useful lives, at an average rate of 4% per annum. The refinery was built on land leased from the State with the lease expiring on July 26, 2097. Repairs and maintenance costs, other than major turnaround costs, were expensed as incurred. Major turnaround costs were capitalized when incurred and amortized over the estimated period of time to the next scheduled turnaround. There were no major turnaround costs incurred during the six month period ended June 30, 2014 prior to the sale.

Revenue from refining operations: Prior to the sale of the refining operations, revenue from sales of products was recognized when products were shipped and the customer had taken ownership and assumed risk of loss, collection of the relevant receivable was probable and when the amount of revenue could be reliably measured. As a result of the sale of the refinery operations, revenue generated from refining operations has been included within the results from discontinued operations for all years presented in the consolidated income statements.

Revenue from distribution operations: Prior to the sale of the distribution operations, sales of goods were recognized when the Company had delivered products to the customer, the customer had taken ownership and assumed risk of loss, collection of the receivable was probable, and when the amount of revenue could be reliably measured. It was not the Company’s policy to sell products with a right of return. As a result of the sale of the distribution operations, revenue generated from distribution operations has been included within the results from discontinued operations for all years presented in the consolidated income statements.

Financial Risk Management applicable to the discontinued operations:

Market Risk:

Prior to the sale of the refinery business, changes in the PGK to USD exchange rate could affect the Company’s refining results as there was a timing difference between the foreign exchange rates utilized when setting the monthly PGK IPP price and the foreign exchange rate used to convert the subsequent receipt of PGK proceeds to USD to repay the Company’s crude cargo borrowings under the working capital facility. The PGK exposures also arise from the exchange rates achieved from the banks on transfer of USD funds to PGK, where the rates achieved fluctuate significantly based on other exporters/importers looking to convert their USD into PGK, and is also impacted by seasonality based farm produce exports from PNG. The Company is unable to hedge due to PGK illiquidity and small size of the market. The translation of PGK denominated balances in the Company’s operating entities into USD at period ends can also result in material impact on the foreign exchange gains/losses on consolidation.

Consolidated Financial Statements INTEROIL CORPORATION 30

InterOil Corporation

Notes to Consolidated Financial Statements

(Expressed in United States dollars)

Discontinued operations (cont’d)

Prior to the sale of the distribution business, the foreign exchange movement also impacted equity as translation gains/losses of the Company’s distribution operations from PGK to USD was included in other comprehensive income.

Product Price Risk:

Prior to the sale of operations, the refinery was largely exposed to price fluctuations during the period between the crude purchases and the refined products leaving the refinery when sold to the Company’s distribution operations and other distributors. The Company actively tried to manage the price risk by entering into derivative contracts to buy and sell crude and finished products.

The derivative contracts were entered into by management based on documented risk management strategies which had been approved by the Risk Management Committee. All derivative contracts entered into were reviewed by the Risk Management Committee as part of the meetings of the Committee.

The following table summarizes the sensitivity of derivative financial instruments held at December 31, 2013 and 2012 to $10.0 movement in benchmark pricing, with all other variables held constant. If the pricing increases/(declines) by $10.0, it will result in a (loss)/gain as per the table below.

	Year ended				Year ended					Year ended
	December 31, 2014				December 31, 2013					December 31, 2012
	Impact on profit		Impact on equity - excluding profit impact		Impact on profit			Impact on equity - excluding profit impact		Impact on profit			Impact on equity - excluding profit impact
	$		$		$			$		$			$

Post-tax gain/(loss)
$10 increase in benchmark pricing of derivative contracts		-		-		(19,160,000	)		-		(1,970,000	)		-

Product risk

The composition of the crude feedstock will vary the refinery output of products. Prior to the sale of the refinery operations, management endeavored to manage the product risk by actively reviewing the market for demand and supply, trying to maximize the production of the higher margin products and also renegotiating the selling prices for the lower margin products.

Other Notes in relation to discontinued operations:

(a)

Cash and cash equivalents:

Cash held as deposit on the BNP working capital facility supported the Company’s working capital facility with BNP Paribas Capital (Singapore) Limited (“BNP Paribas). The working capital facility and associated cash deposit was transferred to Puma under the sale transaction completed on June 30, 2014. The cash held as deposit on the ANZ, BSP and BNP secured loan was used to support the $100.0 million ANZ, BSP and BNP secured loan facility. This facility was fully repaid immediately prior to completion of the sale transaction with Puma.

In 2014, the Company earned nil interest (2013 – nil, 2012 - nil) on the cash on deposit which related to the working capital facility. However, the cash deposit relating to the BNP working capital facility reduced the interest costs relating to the facility usage in 2014 by 3.89% (2013 – 3.56%, 2012 – 3.49%).

(b)

Commodity derivative contracts

Prior to the sale of the refining and distribution business, InterOil used derivative commodity instruments to manage its exposure to price volatility on a portion of its refined product and crude inventories.

At December 31, 2014, InterOil had a net payable of $nil (Dec 2013 – payable of $1,869,253, Dec 2012 – receivable of $233,922) relating to outstanding derivative contracts for which hedge accounting was not applied or had been discontinued.

The Company had no outstanding hedge accounted derivative contracts as at December 31, 2014, December 31, 2013 and December 31, 2012.

Consolidated Financial Statements INTEROIL CORPORATION 31

InterOil Corporation

Notes to Consolidated Financial Statements

(Expressed in United States dollars)

4. Discontinued operations (cont’d)

As at December 31, 2014, the Company had no open non-hedge accounted derivative contracts outstanding. As at December 31, 2013, the Company had the following open non-hedge accounted derivative contracts outstanding.

Notional

Fair Value

Volumes

December 31, 2013

Derivative

Type

(bbls)

Expiry

Derivative type

Brent Swap

Sell Brent

255,000

Q1 2014

Cash flow hedge - Manages the export price risk of naphtha

30,773

Brent Swap

Buy Brent

570,000

Q1 2014

Cash flow hedge - Manages the export price risk of naphtha

(357,943

)

Naphtha Crack Swap

Sell Naphtha Crack

240,000

Q1 2014

Cash flow hedge - Manages the sales price risk of naphtha

(450,756

)

Naphtha Crack Swap

Buy Naphtha Crack

80,000

Q1 2014

Cash flow hedge - Manages the sales price risk of naphtha

190,224

Gasoil Crack Swap

Sell Gasoil Crack

135,000

Q1 2014

Cash flow hedge - Manages the sales price risk of gasoil (diesel)

137,547

Naphtha Crack Swap

Sell Naphtha Crack

135,000

Q2 2014

Cash flow hedge - Manages the sales price risk of naphtha

(14,699

)

Gasoil Crack Swap

Sell Gasoil Crack

135,000

Q2 2014

Cash flow hedge - Manages the sales price risk of gasoil (diesel)

150,359

Naphtha Crack Swap

Sell Naphtha Crack

48,000

Q3 2014

Cash flow hedge - Manages the sales price risk of naphtha

(50,760

)

Gasoil Crack Swap

Sell Gasoil Crack

135,000

Q3 2014

Cash flow hedge - Manages the sales price risk of gasoil (diesel)

110,318

Naphtha Crack Swap

Sell Naphtha Crack

48,000

Q4 2014

Cash flow hedge - Manages the sales price risk of naphtha

(55,758

)

Gasoil Crack Swap

Sell Gasoil Crack

135,000

Q4 2014

Cash flow hedge - Manages the sales price risk of gasoil (diesel)

74,250

(236,445

)

Add: Priced out non-hedge accounted contracts as at December 31, 2013

(1,632,808

)

(1,869,253

)

As at December 31, 2012, the Company had the following open non-hedge accounted derivative contracts outstanding.

Notional

Fair Value

Volumes

December 31, 2012

Derivative

Type

(bbls)

Expiry

Derivative type

Brent Swap

Sell Brent

260,000

Q1 2013

Cash flow hedge - Manages the export price risk of naphtha

(50,523

)

Brent Swap

Buy Brent

280,000

Q1 2013

Cash flow hedge - Manages the export price risk of naphtha

(306,849

)

Naphtha Crack Swap

Sell Naphtha Crack

160,000

Q1 2013

Cash flow hedge - Manages the sales price risk of naphtha

(48,264

)

Gasoil Crack Swap

Sell Gasoil Crack

45,000

Q1 2013

Cash flow hedge - Manages the sales price risk of gasoil (diesel)

102,495

Naphtha Crack Swap

Sell Naphtha Crack

96,000

Q2 2013

Cash flow hedge - Manages the sales price risk of naphtha

1,664

Gasoil Crack Swap

Sell Gasoil Crack

45,000

Q2 2013

Cash flow hedge - Manages the sales price risk of gasoil (diesel)

56,250

Naphtha Crack Swap

Sell Naphtha Crack

48,000

Q3 2013

Cash flow hedge - Manages the sales price risk of naphtha

(24,048

)

Gasoil Crack Swap

Sell Gasoil Crack

45,000

Q3 2013

Cash flow hedge - Manages the sales price risk of gasoil (diesel)

39,210

Naphtha Crack Swap

Sell Naphtha Crack

48,000

Q4 2013

Cash flow hedge - Manages the sales price risk of naphtha

(24,448

)

Gasoil Crack Swap

Sell Gasoil Crack

45,000

Q4 2013

Cash flow hedge - Manages the sales price risk of gasoil (diesel)

24,870

(229,643

)

Add: Priced out non-hedge accounted contracts as at December 31, 2012

463,565

233,922

Consolidated Financial Statements INTEROIL CORPORATION 32

InterOil Corporation

Notes to Consolidated Financial Statements

(Expressed in United States dollars)

Discontinued operations (cont’d)

A loss of $2,485,882 was recognized on the non-hedge accounted derivative contracts for the year ended December 31, 2014 (Dec 2013 – $6,011,131, Dec 2012 – $4,240,647). This loss is included in the results from discontinued operations in the consolidated income statement.

(c)

Inventories

	December 31,		December 31,		December 31,
	2014		2013		2012
	$		$		$
Midstream - Refining (crude oil feedstock)		-		25,594,728		75,240,634
Midstream - Refining (refined petroleum product)		-		58,093,392		49,080,697
Midstream - Refining (parts inventory)		-		3,456,545		3,710,903
Downstream (refined petroleum product)		-		70,974,516		66,839,105
		-		158,119,181		194,871,339

The reduction in inventory as at December 31, 2014 is due to the divestment of the operating businesses on June 30, 2014. As at December 31, 2013 no net realizable value write down was necessary. As at December 31, 2012 inventory had been written down to its net realizable value. The write down of $322,535 at December 31, 2012 relating to refined petroleum products is included in the results from discontinued operations within the consolidated income statement. At December 31, 2013, $87,144,665 (Dec 2012 - $128,032,234) of the Midstream Refining inventory balance secured the BNP Paribas working capital facility disclosed at note (d) below.

(d)

Working capital facilities

	December 31,		December 31,		December 31,
	2014		2013		2012
Amounts drawn down	$		$		$
BNP Paribas working capital facility - midstream		-		23,941,251		94,290,479
Westpac working capital facility - downstream		-		9,793,577		-
BSP working capital facility - downstream		-		2,644,203		-
Total working capital facility		-		36,379,031		94,290,479

The reduction in working capital facilities as at December 31, 2014 is due to the divestment of the operating businesses on June 30, 2014 whereby all of the Company’s working capital facilities were transferred to Puma.

BNP Paribas working capital facility

On July 17, 2013, the Company replaced its $240.0 million bilateral working capital facility with BNP Paribas for its Midstream – Refining operation with a $350.0 million working capital syndicated facility led by BNP Paribas. Out of the $350.0 million, $270.0 million was a syndicated secured working capital facility with the support of five banking partners, namely BNP Paribas, Australia and New Zealand Banking Group (PNG) Limited (“ANZ”), the Singapore branch of Natixis S.A, Intesa Sanpaolo S.p.A, and the Bank of South Pacific Limited (“BSP”), which included the ability to discount receivables with recourse up to $30.0 million. The facility was secured by sales contracts, purchase contracts, certain cash accounts associated with the refinery, all crude and refined products of the refinery and trade receivables. In addition, BNP Paribas had provided an $80.0 million bilateral non-recourse discounting facility. The credit portion of the facility bears interest at LIBOR + 3.75% per annum. The facility was renewable in February 2015.

During the six months ended June 30, 2014, the weighted average interest rate was 3.89% (Year ended December 31, 2013 – 3.09%, Year ended December 31, 2012 – 2.67%,) after considering the reduction in interest due to the deposit amounts maintained which reduces the interest being charged on the facility utilization. The discounting fees on this facility for the six months ended June 30, 2014 were $131,617 (year ended December 31, 2014 - $479,443, year ended December 31, 2012 - $456,415).

Consolidated Financial Statements INTEROIL CORPORATION 33

InterOil Corporation

Notes to Consolidated Financial Statements

(Expressed in United States dollars)

Discontinued operations (cont’d)

The following table outlines the facility and the amount available for use at prior year ends:

	December 31,		December 31,			December 31,
	2014		2013			2012
	$		$			$
Working capital credit facility		-		270,000,000			240,000,000

Less amounts included in the working capital facility liability:
Short term advances/facilities drawn down		-		(23,941,251	)		(47,203,152	)
Discounted receivables*		-		-			(47,087,327	)
		-		(23,941,251	)		(94,290,479	)
Less: other amounts outstanding under the facility:
Letters of credit outstanding		-		(167,722,379	)		(139,500,000	)
Working capital credit facility available for use		-		78,336,370			6,209,521

* Under the revised facility, discounted receivables which are non-recourse are not included in the available for use balance as they fall within the separate $80.0 million facility with BNP Paribas. As at December 31, 2013, there were $24,990,929 in discounted receivables outstanding, with $55,009,071 of the non-recourse discounting facility remaining available for use.

The cash deposit on working capital facility at December 31, 2013, as separately disclosed in note 7, included restricted cash of $28,749,544 (2012 - $37,340,631) which was being maintained as a security margin for the facility. In addition, inventory of $87,144,665 (2012 - $128,032,234) and trade receivables of $64,781,779 (2012 - $80,564,430) also secured the facility at December 31, 2013. The trade receivable balance securing the facility at December 31, 2013, included $37,590,034 (2012 - $24,668,107) of inter-company receivables which were eliminated on consolidation.

Westpac and BSP working capital facility

At December 31, 2013, the Company had an approximately $37,170,000 (PGK 90,000,000) revolving working capital facility for its Downstream operations in PNG from BSP and Westpac Bank PNG Limited (“Westpac”), shared equally between the two banks. The Westpac facility was for an initial term of three years and was renewed in November 2011 through to November 2014. The BSP facility was renewable annually and was renewed in August 2013 through to November 2014. As at December 31, 2013, $12,437,780 (PGK 30,115,690) of this combined facility had been utilized. These facilities were secured by a fixed and floating charge over the assets of Downstream operations. During the six months ended June 30, 2014, the weighted average interest rate was 8.4% (Year ended December 31, 2013 – 9.0%, Year ended December 31, 2012 – 10.0%).

(e)

Secured and Unsecured Loans:

Westpac Secured Loan

A secured loan of $15,000,000 was provided as part of the increased Westpac working capital facility which was repayable in equal installments over 3.5 years with an interest rate of LIBOR + 4.4% per annum. The loan was secured by a fixed and floating charge over the assets of Downstream operations. The loan was fully repaid during the year ended December 31, 2013.

ANZ, BSP & BNP Syndicated Loan

On October 16, 2012, the Company entered into a five year amortizing $100 million syndicated secured term loan facility with BNP Paribas Singapore, Bank South Pacific Limited, and Australia and New Zealand Banking Group (PNG) Limited. The loan was secured over the fixed assets of the refinery. The interest rate on the loan was equal to LIBOR plus 6.5%. The loan was fully repaid during the year ended December 31, 2014 as a requirement of the sale agreement with Puma.

BSP & Westpac Secured Facility

On August 19, 2013, the Company entered into a one year $75.0 million equivalent combined secured loan facility with Westpac and BSP to be drawn in tranches, in either USD and/or PGK. Borrowings under the facility were to be used for exploration and drilling activities with $37.5 million available immediately, and a further $37.5 million to be available upon the execution of an agreement in relation to the monetization of the Elk and Antelope resource. Subsequent to the closing of the Credit Suisse A.G (“Credit Suisse”) facility noted below, the second available tranche of $37.5 million was cancelled, and BSP and Westpac have participated within the Credit Suisse led syndication facility. In addition, on November 15, 2013, the loan facility was further amended to reduce the combined limit to approximately $24.8 million (PGK 60.0 million). The loan was fully repaid during the year ended December 31, 2014 as a requirement of the sale agreement with Puma.

Consolidated Financial Statements INTEROIL CORPORATION 34

InterOil Corporation

Notes to Consolidated Financial Statements

(Expressed in United States dollars)

Discontinued operations (cont’d)

(f)

Asset retirement obligations

The following table shows the movement in the asset retirement obligation during the period:

	December 31,			December 31,			December 31,
	2014			2013			2012
	$			$			$
Opening balance		4,948,017			4,978,334			4,562,269
Accretion of provision		192,282			356,830			331,096
Foreign exchange impact on translation of provision		-			(387,147	)		84,969
Disposal of subsidiary		(5,140,299	)		-			-
Closing balance		-			4,948,017			4,978,334

The reduction in the asset retirement obligation as at December 31, 2014 is due to the divestment of the operating businesses on June 30, 2014. Prior to the divestment, the Company had planned to dismantle the refinery and restore the site when the refinery was decommissioned. In January 2013, Management received the final results of an independent assessment of the potential asset retirement obligations of the refinery at the time of decommissioning. This assessment supported the value of the provision of $4,100,735 that was originally recognized in 2011 for the present value of the estimated expenditure required to complete this obligation. The inflation factor used in the independent assessment of the retirement obligation is 2.6% and the fair value of the best estimate was derived based on discounting the obligation to the current period end using a discount rate of 7.78%. These costs were capitalized as part of the cost of the refinery and were being depreciated over the life of the asset. The provision was being accreted over the remaining useful life of the refinery to bring the provision to the estimated expenditure required at the time of decommissioning. The accretion expense for the six months ended June 30, 2014 was $192,282 (Year ended December 31, 2013 - $356,830, Year ended December 31, 2012 - $331,096).

Cash and cash equivalents

The components of cash and cash equivalents are as follows:

	December 31,		December 31,		December 31,
	2014		2013		2012
	$		$		$
Cash on deposit		393,405,198		61,738,440		49,461,096
Bank term deposits
- Papua New Guinea kina deposits		-		228,099		259,584
		393,405,198		61,966,539		49,720,680

In 2014, cash and cash equivalents earned an average interest rate of 0.17% per annum (2013 – 0.09%, 2012 – 0.14%).

Supplemental cash flow information

	Year ended
	December 31,		December 31,		December 31,
	2014		2013		2012
	$		$		$
Cash paid during the period
Interest (including interest withholding tax)		11,273,098		13,018,526		17,660,696
Income taxes		1,781,009		6,614,262		8,061,922
Interest received		1,066,804		75,417		239,284
Non-cash financing activities:
Increase in share capital from:
the exercise of share options and vesting of restricted stock		9,732,565		12,380,121		11,649,459
buyback of PNGEI investor rights		-		6,837,000		-
buyback of indirect participation interests		41,525,728		-		-

Consolidated Financial Statements INTEROIL CORPORATION 35

InterOil Corporation

Notes to Consolidated Financial Statements

(Expressed in United States dollars)

Financial instruments

(a)

Cash and cash equivalents

With the exception of cash and cash equivalents and restricted cash, all financial assets are non-interest bearing. Cash restricted, which mainly relates to the Credit Suisse secured loan, is comprised of the following:

	December 31,		December 31,		December 31,
	2014		2013		2012
	$		$		$
Cash deposit on working capital facility (0.0%)		-		28,749,544		37,340,631
Debt reserve for Credit Suisse secured loan (0.05%)		7,959,859		7,400,000		-
Cash restricted - Current		7,959,859		36,149,544		37,340,631

Bank term deposits on Petroleum Prospecting Licenses (0.7%)		178,155		147,372		167,329
Cash deposit on office premises (2.7%)		163,119		177,446		207,426
Cash deposit on ANZ, BSP and BNP secured loan (0.0%)		-		11,240,182		11,295,708
Cash deposit on drill rig (0.0%)		-		5,500,000		-
Cash restricted - Non-current		341,274		17,065,000		11,670,463
		8,301,133		53,214,544		49,011,094

Please refer to note 4 for details of all facilities related to the discontinued operations.

The debt reserve for the Credit Suisse led secured loan facility is used to support the Company’s secured loan borrowings and is equivalent to the interest payable within six months of the first draw down on the facility.

The cash held as deposit on the drill rig for the year ended December 31, 2013 is a result of the requirement for the Company to provide a letter of credit to a supplier on the signing of a rig lease and services agreement. The original letter of credit was replaced in 2014 with a letter of credit that did not require cash to be held in deposit.

Bank term deposits on PPLs are unavailable for use while PPL 474, 475, 476 and 477 are being utilized by the Company.

(b)

Currency derivative contracts

The Company enters into AUD to USD foreign currency forward contracts to minimize the foreign exchange risk in relation to the expenses to be incurred in AUD, however no such contracts were entered into during the year ended December 31, 2014.

A gain of $nil was recognized on the non-hedge accounted currency derivative contracts for the year ended December 31, 2014 (Dec 2013 – loss of $146,100, Dec 2012 – gain of $11,457). This loss is included in derivative (losses)/gains in the consolidated income statement.

Trade and other receivables

	December 31,		December 31,		December 31,
	2014		2013		2012
	$		$		$
Trade and other receivables		21,207,984		98,638,110		161,578,481
Sale proceeds receivable from Total S.A.		545,154,761		-		-
Total		566,362,745		98,638,110		161,578,481

The reduction in trade and other receivables as at December 31, 2014 is due to the divestment of the operating businesses on June 30, 2014. Other receivables mainly relates to cash calls receivable from joint venture partners.

At December 31, 2013, $64,781,779 (Dec 2012 - $80,564,430) of the trade and other receivables secured the BNP Paribas working capital facility disclosed in note 4 (d). This balance included $37,590,034 (Dec 2012 - $24,668,107) of intercompany receivables which were eliminated on consolidation.

Consolidated Financial Statements INTEROIL CORPORATION 36

InterOil Corporation

Notes to Consolidated Financial Statements

(Expressed in United States dollars)

Trade and other receivables

Sale proceeds receivable from Total

Refer to note 10 for details of the Total SSA. The Interim Resource Payment, as defined under the Total SSA, due to the Company following the interim certification has been calculated to be $593,887,429 based on a resource estimate of 7.10 Tcfe. The original expected discounted value of this cash flow as calculated at March 31, 2014 as at year ended 2014 was $576,719,382. However, during December 2014 the Company has adjusted the expected cash flow timing of the Interim Resource Payment to the end of 2015 to accommodate the drilling of the Antelope-6 optional appraisal well that is included within the agreement. The Company has recalculated the carrying amount of the receivable by computing the present value of estimated future cash flows at the original effective interest rate and the adjustment has been recognized in profit or loss. The Company has recalculated the carrying amount of the receivable as at December 31, 2014 to be $552,512,599, with the resulting adjustment of $24,206,783 being recognized in the income statement during the quarter ended December 31, 2014.

The Company has recognized $24,826,440 as a result of unwinding the discount on the receivable as interest income during the year ended December 31, 2014. This interest income has been offset by the adjustment above, resulting in net interest income of $619,657 being recognized during the year ended December 31, 2014. In addition, this receivable has been reduced by $7,357,838, which represents a portion of the carry received from Total for development activities undertaken over PRL 15, which is to be offset against the Interim Resource Payment when due. The following table shows the movement in the receivable during the year ended December 31, 2014.

	December 31,			December 31,		December 31,
	2014			2013		2012
	$			$		$
Initial recognition of receivable from Total		551,892,942			-		-
Interest accretion income on receivable from Total		24,826,440			-		-
Adjustment due to change in timing of estimated cash flows		(24,206,783	)		-		-
less amounts received from Total for carry of appraisal costs		(7,357,838	)		-		-
		545,154,761			-		-

Consolidated Financial Statements INTEROIL CORPORATION 37

InterOil Corporation

Notes to Consolidated Financial Statements

(Expressed in United States dollars)

Plant and equipment

	Refinery			Land and Buildings			Plant and Equipment			Motor Vehicles			Deferred Project Costs and Work in Progress			Totals
At January 1, 2012:
Opening net book value		176,766,929			16,783,587			23,623,449			3,832,441			25,024,972			246,031,378
Additions		2,048,211			1,505,281			1,935,145			229,539			25,641,838			31,360,014
Disposals		-			(1,225,329	)		(993,525	)		(57,011	)		-			(2,275,865	)
Transfers from work in progress		4,740,349			12,233,962			7,392,127			1,550,643			(25,917,081	)		-
Reclassification to other asset categories		(88,547	)		-			88,547			-			-			-
Depreciation for the period		(11,904,138	)		(1,485,314	)		(5,312,874	)		(1,477,509	)		-			(20,179,835	)
Exchange differences		(418,932	)		9,676			256,675			(9,911	)		258,057			95,565
Closing net book value		171,143,872			27,821,863			26,989,544			4,068,192			25,007,786			255,031,257

At December 31, 2012:
Cost		255,394,975			40,715,833			62,051,336			9,810,445			25,007,786			392,980,375
Accumulated depreciation		(84,251,103	)		(12,893,970	)		(35,061,792	)		(5,742,253	)		-			(137,949,118	)
Net book value		171,143,872			27,821,863			26,989,544			4,068,192			25,007,786			255,031,257

Year ended December 31, 2013:
Opening net book value		171,143,872			27,821,863			26,989,544			4,068,192			25,007,786			255,031,257
Additions		-			627,936			671,202			112,780			18,662,673			20,074,591
Disposals		(156,913	)		(202,341	)		(817,904	)		(7,109	)		-			(1,184,267	)
Transfers from work in progress		5,351,782			2,698,044			7,422,570			1,403,748			(16,876,144	)		-
Reclassification to other asset categories		-			551,078			(551,078	)		-			-			-
Depreciation for the period		(12,346,045	)		(2,011,357	)		(5,375,114	)		(1,575,983	)		-			(21,308,499	)
Exchange differences		-			(2,289,019	)		(2,867,830	)		(475,794	)		(2,596,477	)		(8,229,120	)
Closing net book value		163,992,696			27,196,204			25,471,390			3,525,834			24,197,838			244,383,962

At December 31, 2013:
Cost		259,735,971			40,282,049			57,110,405			9,222,237			24,197,838			390,548,500
Accumulated depreciation		(95,743,275	)		(13,085,845	)		(31,639,015	)		(5,696,403	)		-			(146,164,538	)
Net book value		163,992,696			27,196,204			25,471,390			3,525,834			24,197,838			244,383,962

Year ended December 31, 2014:
Opening net book value		163,992,696			27,196,204			25,471,390			3,525,834			24,197,838			244,383,962
Additions		-			49,207			87,840			-			11,726,541			11,863,588
Disposals		(166,504	)		-			(447,884	)		(5,767	)		-			(620,155	)
Transfers from work in progress		5,079,416			1,560,196			8,718,393			1,687,951			(17,045,956	)		-
Reclassification to other asset categories		-			180,897			(180,897	)		-			-			-
Depreciation for the period		(5,824,249	)		(1,554,616	)		(4,220,679	)		(954,239	)		-			(12,553,783	)
Exchange differences		-			(38,107	)		(61,581	)		(8,109	)		(23,836	)		(131,633	)
Disposal of subsidiaries		(163,081,359	)		(20,767,490	)		(25,157,263	)		(3,552,204	)		(18,120,298	)		(230,678,614	)
Closing net book value		-			6,626,291			4,209,319			693,466			734,289			12,263,365

At December 31, 2014:
Cost		-			9,935,809			5,028,356			1,013,838			734,289			16,712,292
Accumulated depreciation		-			(3,309,518	)		(819,037	)		(320,372	)		-			(4,448,927	)
Net book value		-			6,626,291			4,209,319			693,466			734,289			12,263,365

Consolidated Financial Statements INTEROIL CORPORATION 38

InterOil Corporation

Notes to Consolidated Financial Statements

(Expressed in United States dollars)

10.

Exploration and evaluation assets

Costs of exploration and evaluation assets which are not subject to depletion are as follows:

	December 31,		December 31,		December 31,
	2014		2013		2012
	$		$		$
Infrastructure and drilling and construction equipment		1,759,251		205,116,854		145,854,653
Drilling consumables and spares		32,659,831		20,452,801		17,847,114
Petroleum Retention License drilling programs (Unproved)		83,939,901		349,043,785		-
Petroleum Prospecting License drilling programs (Unproved)		206,682,990		10,193,583		346,967,664
Gross Capitalized Costs		325,041,973		584,807,023		510,669,431
Accumulated depletion and amortization
Unproved oil and gas properties		-		-		-
Proved oil and gas properties		-		-		-
Net Capitalized Costs		325,041,973		584,807,023		510,669,431

The majority of the costs capitalized under ‘Petroleum Retention License drilling programs’ above relates to the exploration and development expenditure on the Elk, Antelope and Triceratops fields. The majority of the costs capitalized under ‘Petroleum Prospecting License drilling programs (Unproved)’ above relates to the exploratory drilling costs relating to Wahoo-1, Bobcat-1 and Raptor-1 wells.

The reduction in exploration and evaluation assets during the year ended December 31, 2014 related to the offsetting of the exploration and development expenditure on the Elk and Antelope field against the proceeds of the sale of an interest in PRL 15 to Total. This is in line with the requirements for conveyance accounting for unproved property, which requires the amounts received on sale to be treated as a recovery of cost, and only if the sale price exceeds the carrying value of property that a gain be recognized.

The following table discloses a breakdown of the exploration and evaluation costs incurred for the periods ended:

	Year ended			Year ended			Year ended
	December 31,			December 31,			December 31,
	2014			2013			2012
	$			$			$
Opening balance		584,807,023			510,669,431			362,852,766
Property Acquisition Costs		-			-			-
Exploration Costs		256,562,981			12,890,150			-
Development Costs		194,291,826			116,127,393			179,779,865
Add: Premium paid on IPI buyback transactions		41,525,728			-			-
Less: IPI conveyance accounting offset against properties (note 14)		(12,097,363	)		(12,451,617	)		(12,999,752	)
Less: Total S.A. conveyance accounting offset against properties		(611,939,426	)		-			-
Less: Costs recovered through cash calls from joint venture partners		(128,108,796	)		(42,428,334	)		(18,963,448	)
Total Costs capitalized		(259,765,050	)		74,137,592			147,816,665
Closing balance		325,041,973			584,807,023			510,669,431
Charged to expense
Geophysical and other costs		34,529,478			18,793,902			13,901,558
Total charged to expense		34,529,478			18,793,902			13,901,558
Exploration and Evaluation Assets Net Additions (capitalized and expensed)		(225,235,572	)		92,931,494			161,718,223

The following table discloses a breakdown of the gain realized on conveyance of exploration and evaluation assets for the periods ended:

	Year ended
	December 31,		December 31,		December 31,
	2014		2013		2012
	$		$		$

Gain on conveyance of oil and gas properties
Conveyance of PPL 237 interest to PRE		-		-		2,894,957
Conveyance accounting of IPI Agreement (note 14)		-		500,071		1,523,213
Conveyance of PRL 15 interest (40.1275% of the property)		340,540,011		-		-
		340,540,011		500,071		4,418,170

Consolidated Financial Statements INTEROIL CORPORATION 39

InterOil Corporation

Notes to Consolidated Financial Statements

(Expressed in United States dollars)

10.

Exploration and evaluation assets (cont’d)

Total Sale and Purchase Agreement for PRL 15:

On March 26, 2014, the Company signed and closed the Total SSA, under which Total acquired through the purchase of all shares in a wholly owned subsidiary of InterOil, a gross 40.1275% interest in PRL 15, which contains the Elk and Antelope gas fields. InterOil received $401.3 million for closing the transaction, and became entitled to receive $73.3 million upon a final investment decision for an Elk and Antelope LNG project, and $65.5 million upon the first LNG cargo from such LNG project. In addition to these fixed amounts, Total is obliged to make variable payments for gas amounts 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 gas resource payment for amounts greater than 5.4 Tcfe will be paid at certification.

Conveyance accounting:

Based on the accounting policies followed by the Company, conveyance accounting is triggered on the sale of a property, where applying judgment to the facts presented, it concludes that sufficient risks and benefits of ownership has passed to the transferee. If a part of the interest in an unproved property is sold, the amount received shall be treated as a recovery of cost. If the sales price exceeds the carrying amount of a property, a gain shall be recognized in the amount of such excess. As the Elk and Antelope fields do not have proved reserves as at the date of accounting for this transaction, the amounts received are first treated as a recovery of cost, and only amounts received over the carrying amount of property is booked as a gain on conveyance of the asset.

The conveyance accounting for the Total SSA has been recorded for in the year ended December 31, 2014. The following table presents the cash flows and the resulting gain on conveyance that has been recorded for the year ended December 31, 2014.

Conveyance accounting (excluding FID and cargo payments, and appraisal carry on wells within PRL 15) based on Gaffney Cline certified best case scenario of 7.10 Tcfe	Year ended December 31, 2014 $

Conveyance proceeds received		401,338,497
Conveyance proceeds receivable		593,887,729
		995,226,226

Discounted value of cash flows		953,231,438
Less allocation against oil and gas properties in the balance sheet		(611,939,426	)
Less discounted value of cash flows payable to IPI partners		(752,001	)
Gain on conveyance for the period		340,540,011

No cash flows relating to final investment decision or subsequent first LNG cargo payments relating to the Elk and Antelope fields have been included within the cash flows calculation above. The discounted value of cash flows has been calculated using a discount rate of 8.23%. In deriving the discount rate, management has used the risk free rate on US treasury securities and added a risk premium on lending for PNG.

On March 26, 2014, the Company also completed the acquisition from IPI (as defined herein) holders of an additional 1.0536% participating interest in PRL 15 for consideration of $41.53 million satisfied by the issuance of 688,654 common shares of the Company, plus additional variable resource payments if interim or final resource certifications exceeds 7.0 Tcfe under the Total SSA. Accordingly, the gain on conveyance for the Total transaction has been reduced by the discounted value of cash flows that would be payable to the IPI holders assuming a resource estimate of 7.10 Tcfe.

At each following reporting period, the risk free rate and the timing of expected cash flows will be assessed to take into account any changes to the underlying risk factors used in the calculation along with changes to resource estimates. At December 31, 2014, the Company has adjusted the expected cash flow timing of the Interim Resource Payment to the end of 2015 to accommodate the drilling of Antelope-6 optional appraisal well that is included within the agreement. The Company has recalculated the carrying amount of the receivable from that initially calculated at March 31, 2014, by computing the present value of estimated future cash flows at the original effective interest rate and the adjustment has been recognized in profit or loss as income or expense. Refer to note 8 for further details regarding this adjustment.

Resource estimate used:

The cash flows listed above have been calculated using the best case scenario provided by Gaffney Cline & Associates (“GCA”) of 7.10 Tcfe for the Elk and Antelope fields. GCA is a recognized certifier under the Total SSA. The interim resource certification under the Total SSA will be determined post the completion of up to three appraisal wells that will be drilled within Elk and Antelope fields prior to the certification.

Consolidated Financial Statements INTEROIL CORPORATION 40

InterOil Corporation

Notes to Consolidated Financial Statements

(Expressed in United States dollars)

10.

Exploration and evaluation assets (cont’d)

The above calculation also does not take into account any potential discovery bonus payable by Total to InterOil in the event that the required exploration well to be drilled within the area covered by PRL 15, but outside the Elk and Antelope fields, is successful in identifying hydrocarbons.

11.

Income taxes

(a)

Income tax expense

The combined income tax expense in the consolidated income statements reflects an effective tax rate which differs from the expected statutory rate (combined federal and provincial rates). Differences for the years ended were accounted for as follows:

	December 31,			December 31,			December 31,
	2014			2013			2012
	$			$			$
Profit/(loss) before income taxes and non controlling interest from continuing operations		219,081,760			(57,975,844	)		(32,166,842	)
Statutory income tax rate		30.00	%		30.00	%		30.00	%
Computed tax expense/(benefit)		65,724,528			(17,392,753	)		(9,650,053	)

Effect on income tax of:
(Income)/losses in foreign jurisdictions not (assessable)/deductible		(376,393	)		(4,158,530	)		1,167,531
Non-deductible stock compensation expense		1,106,252			841,840			709,133
Non-deductible interest expense		754,098			658,680			-
Non-taxable gain on conveyance of exploration assets		(101,455,049	)		(150,021	)		(868,487	)
Effect of currency translation on tax base		231,432			49,324			(20,732	)
Tax rate differential in foreign jurisdictions		(210,277	)		(85,267	)		(71,038	)
Under provision for income tax in prior years		(32,983	)		284,738			(298,680	)
Tax losses for which no future tax benefit has been brought to account		35,645,618			21,563,410			10,508,508
Other - net		(267,796	)		(671,202	)		(1,155,432	)
Income tax expense from continuing operations		1,119,430			940,219			320,750

Gains of a capital nature do not constitute ordinary income in Papua New Guinea for taxation purposes; hence the gain on conveyance of exploration assets in the table above is noted as non-taxable.

(b)

Deferred income tax

The gross movement on the deferred income tax account is as follows:

	December 31,			December 31,			December 31,
	2014			2013			2012
	$			$			$
At January 1		48,230,688			63,526,458			34,075,882
Charge to the income statement (continuing operations)		(557,406	)		(222,981	)		390,529
Charge to the income statement (discontinued operations)		(1,211,177	)		(6,782,564	)		26,204,149
Disposal of subsidiaries		(46,353,729	)		-			-
Exchange differences		(108,376	)		(8,290,225	)		2,855,898
At December 31		-			48,230,688			63,526,458

The movement in deferred income tax assets and liabilities during the year, without taking into consideration the offsetting of balances within the same tax jurisdiction, is as follows:

Consolidated Financial Statements INTEROIL CORPORATION 41

InterOil Corporation

Notes to Consolidated Financial Statements

(Expressed in United States dollars)

11.

Income taxes (cont’d)

	Tax losses			Other			Tax depreciation			Unrealized foreign exchange (gains)/losses			Total
Deferred tax assets and liabilities	$			$			$			$			$
At January 1, 2012		24,771,273			2,208,183			15,679,200			(8,582,774	)		34,075,882
Charge to the income statement (continuing operations)		-			13,338			336,988			40,203			390,529
Charge to the income statement (discontinued operations)		21,770,947			60,214			(2,233,348	)		6,606,336			26,204,149
Exchange differences		336,733			68,849			325,325			2,124,991			2,855,898
At December 31, 2012		46,878,953			2,350,584			14,108,165			188,756			63,526,458
Charge to the income statement (continuing operations)		-			151,848			(367,176	)		(7,653	)		(222,981	)
Charge to the income statement (discontinued operations)		(2,670,996	)		1,623,353			(7,543,666	)		1,808,745			(6,782,564	)
Exchange differences		(6,110,368	)		(528,958	)		(1,497,181	)		(153,718	)		(8,290,225	)
At December 31, 2013		38,097,589			3,596,827			4,700,142			1,836,130			48,230,688
Charge to the income statement (continuing operations)		-			(776,253	)		191,696			27,151			(557,406	)
Charge to the income statement (discontinued operations)		(322,830	)		1,531,903			(830,634	)		(1,589,616	)		(1,211,177	)
Disposal of subsidiaries		(37,676,732	)		(4,349,462	)		(4,059,244	)		(268,291	)		(46,353,729	)
Exchange differences		(98,027	)		(3,015	)		(1,960	)		(5,374	)		(108,376	)
At December 31, 2014		-			-			-			-			-

The Company has temporary differences and losses carried forward in relation to exploration expenditure incurred in PNG of $903,994,344 at December 31, 2014. No deferred tax assets have been recognized for this exploration expenditure. Management will consider the recognition of the deferred tax assets when there is more certainty around the timing of assessable income in the Company’s operations.

The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the actual levels of past taxable income, scheduled reversal of deferred tax liabilities, projected future taxable income, projected tax rates and tax planning strategies in making this assessment.

12.

Trade and other payables

	December 31,		December 31,		December 31,
	2014		2013		2012
	$		$		$
Trade payables - crude import		-		58,984,337		35,992,153
Trade payables - product import		-		-		29,539,390
Other accounts payable and accrued liabilities		124,281,105		59,608,010		83,894,702
Petromin cash calls received		15,435,000		15,435,000		15,435,000
Mitsui cash calls received		-		-		13,452,238
Total trade and other payables		139,716,105		134,027,347		178,313,483

(a) Petromin participation in Elk and Antelope fields

On October 30, 2008, Petromin PNG Holdings Limited (”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. The State’s (and Petromin’s) right to take an interest arises upon issuance of the Prospecting Development License (”PDL”), which has not yet occurred. The obligation to fund its portion of the costs of developing the field, including sunk costs, also applies upon issuance of the PDL. As at December 31, 2014, $15,435,000 in advance payments received from Petromin has been held under ‘Petromin cash calls received’ above. At the end of the 2011 year, the parties agreed that the agreement’s intended operation had ended, and that it should terminate. InterOil has proposed that cash contributions made by Petromin to date to fund the development will be held and credited against the State’s obligation to contribute its portion of sunk costs upon grant of the PDL.

Consolidated Financial Statements INTEROIL CORPORATION 42

InterOil Corporation

Notes to Consolidated Financial Statements

(Expressed in United States dollars)

13.

Secured and unsecured loans

	December 31,		December 31,			December 31,
	2014		2013			2012
	$		$			$
Secured loan (Westpac) - current portion		-		-			4,286,000
Secured loan (ANZ, BSP & BNP Syndication) - current portion		-		16,000,000			16,000,000
Secured loan (ANZ, BSP & BNP Syndication) - deferred financing costs		-		(818,315	)		(815,182	)
Secured loan (BSP & Westpac facility)		-		24,780,077			-
Secured loan (BSP & Westpac facility) - deferred financing costs		-		(1,012,178	)		-
Secured loan (Credit Suisse)		-		100,000,000			-
Secured loan (Credit Suisse) - deferred financing costs		-		(4,174,507	)		-
Unsecured loan (Mitsui)		-		-			11,912,297
Total current portion of loans		-		134,775,077			31,383,115

Secured loan (ANZ, BSP & BNP Syndication) - non current portion		-		68,000,000			84,000,000
Secured loan (ANZ, BSP & BNP Syndication) - deferred financing costs		-		(2,318,575	)		(3,124,863	)
Secured loan (Westpac) - non current portion		-		-			8,571,000
Total non current secured loan		-		65,681,425			89,446,137

Total secured and unsecured loans		-		200,456,502			120,829,252

Please refer to note 4 for details of all facilities related to the discontinued operations.

(a)

Credit Suisse Secured Facility

On November 11, 2013, the Company entered into a $250.0 million secured syndicated capital expenditure facility led by Credit Suisse AG related to an approved seismic data acquisition and drilling program. In addition to Credit Suisse, the participating lenders were Commonwealth Bank of Australia (“CBA”), ANZ, UBS AG, Macquarie Group Limited (“Macquarie”), BSP, BNP Paribas and Westpac. The facility is secured by the Company’s existing Upstream and Corporate entities. On June 17, 2014, the Company replaced the $250.0 million facility with a $300.0 million syndicated, senior secured capital expenditure facility through a consortium of banks led by Credit Suisse AG. The facility was supported by the participating lenders under the original facility in addition to new banks, The Bank of Tokyo-Mitsubishi UFJ (“MUFG”) and Societe Generale S.A (“SocGen”). The new facility has an annual interest rate of LIBOR plus 5% and matures at the end of 2015. No drawdowns have been made under the new facility as at December 31, 2014.

During the year ended December 31, 2014 the weighted average interest rate was 5.74% (Dec 2013 – 5.65%) and the total interest expense included in finance costs was $4,303,388 (Dec 2013 - $471,201). In addition, financing costs relating to the loan of $16,850,197 (of which $6,143,560 relates to the refinancing completed in June 2014 and $4,174,507 relates to the deferred financing costs as at December 31, 2013) were expensed during the year ended December 31, 2014.

As at December 31, 2014, the Company is in compliance with the applicable debt covenants, which included a defined calculation for gearing not to exceed 60% at any time, and the equity does not fall below $500 million at any time.

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

(b)

Mitsui Unsecured Loan

On July 16, 2013, the Company entered into a Settlement and Termination Deed with Mitsui & Co., Ltd (“Mitsui”) following the termination of the CSP JVOA on February 28, 2013. In accordance with the Deed, the Company repaid Mitsui $6,250,000 in relation to the option to acquire interests in the Elk and Antelope fields, $9,537,212 on July 31, 2013, $9,194,376 on August 30, 2013 and $9,394,159 on September 30, 2013 being the three installments required in relation to Mitsui’s share of capital expenditure incurred, the unsecured loan, together with interest thereon. The facility has now been fully repaid.

Consolidated Financial Statements INTEROIL CORPORATION 43

InterOil Corporation

Notes to Consolidated Financial Statements

(Expressed in United States dollars)

14.

Indirect participation interests

	December 31,		December 31,		December 31,
	2014		2013		2012
	$		$		$
Indirect participation interest (PNGDV) - current portion		-		-		1,384,492
Indirect participation interest ("IPI") - current portion		7,449,409		12,097,363		13,861,905
Total current indirect participation interest		7,449,409		12,097,363		15,246,397

Indirect participation interest ("IPI") - non current portion		-		7,449,409		16,405,393
Total non current indirect participation interest		-		7,449,409		16,405,393

Total indirect participation interest		7,449,409		19,546,772		31,651,790

During the year ended December 31, 2014, $12,097,363 of the costs incurred on the Raptor-1, Wahoo-1 and Bobcat-1 exploration wells have been allocated against the IPI liability. As at December 31, 2014, the IPI liability relating to one remaining exploration well that is expected to be drilled within the next twelve month period is within the current portion of the liability.

(a) Indirect participation interest (“IPI”)

The IPI balance relates to $125,000,000 received by InterOil subject to the terms of the agreement dated February 25, 2005 between the Company and a number of investors. In exchange InterOil had provided the investors with a 25% interest in an eight well drilling program to be conducted in InterOil’s PPL 236, 237 and 238, which have since been replaced by PPL 474, 475, 476 and 477.

Under the IPI agreement, InterOil is responsible for drilling eight exploration wells. In the instance that InterOil proposes appraisal or completion of an exploration or development well, the investors will be asked to contribute to the completion work in proportion to their IPI percentage and InterOil will bear the remaining cost.

InterOil has made cash calls for the completion, appraisal and development programs performed on the exploration or development wells that form part of the IPI agreement. Cash calls made in advance are shown as a liability when received and reduced as amounts are spent on the extended well programs, whereas cash calls made in arrears are shown as a reduction to amounts previously recognized as receivable as the amounts were spent on the extended well programs. Should an investor choose not to participate in the completion works of an exploration well, the investor will forfeit certain rights to the well in question as well as their right to convert into common shares. InterOil has drilled seven exploration wells under the IPI agreement as at December 31, 2014.

The funds of $125,000,000 were partly accounted for as a non-financial liability and partly as a conversion option. The non-financial liability was initially valued at $105,000,000, being the estimated expenditures to complete the eight well drilling program, and the residual value of $20,000,000 has been allocated to the conversion option presented under Shareholder’s equity. InterOil paid financing fees and transaction costs of $8,138,741 related to the indirect participation interest on behalf of the indirect participation interest investors in 2005. These fees have been allocated against the non-financial liability, reducing the liability to $96,861,259. InterOil will account for the exploration costs relating to the eight well program under the successful efforts accounting policy adopted by the Company. All geological and geophysical costs relating to the exploration program will be expensed as incurred and all drilling costs will be capitalized and assessed for recovery at each period.

When an investor elects to participate in a PRL or when the investor forfeits the conversion option, conveyance accounting will be applied. This entails determination of proceeds for the interests conveyed and the cost of that interest as represented in the ‘Oil and gas properties’ in the balance sheet. The difference between proceeds on conveyance and capitalized costs to the interests conveyed will be recognized as gain or loss in the income statement. As at December 31, 2014, none of the IPI investors had any conversion rights outstanding.

From the date of the agreement up to December 31, 2014, the following transactions have occurred:

(i) Increase in InterOil’s direct interest in the IPI program by 10.915% due to the following:

Conversion of IPI interests: Prior to the year ended December 31, 2014, certain IPI investors representing a 3.575% interest in the IPI agreement have exercised their right to convert their interest into common shares resulting in issuance of 476,667 InterOil common shares. These conversions reduced the initial IPI liability balance by $13,851,160 and the initial conversion option balance by $2,860,000.

Consolidated Financial Statements INTEROIL CORPORATION 44

InterOil Corporation

Notes to Consolidated Financial Statements

(Expressed in United States dollars)

14.

Indirect participation interests (cont’d)

Buyback of IPI interests by the Company: Prior to the year ended December 31, 2014, certain IPI investors representing a 6.2864% interest in the IPI agreement have sold their interest to the Company. On March 26, 2014, the Company completed the acquisition 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.

(ii) Waiver or forfeiture of conversion rights resulting in conveyance accounting

Certain IPI investors representing a 14.1386% interest in the IPI agreement have waived their right to convert their IPI percentage into 1,885,147 common shares. As a result, conveyance was triggered on this portion of the IPI agreement, which reduced the IPI liability by $37,091,615.

During the year ended December 31, 2012, several IPI investors were registered on PRL 15. Under the IPI Agreement, when an investor is registered on a PRL, they forfeit their right to convert their IPI percentage into common shares. One of the investors now registered on PRL 15 had not previously waived their right to convert their 1% percent interest into 133,333 common shares. Therefore, following registration on PRL 15, their conversion rights have now been forfeited and conveyance was triggered on this portion of the IPI agreement, which reduced the IPI liability by $2,015,368.

(b) Indirect participation interest – PNGDV

As at December 31, 2014, the balance of the PNG Drilling Ventures Limited ("PNGDV") indirect participation interest in the Company’s phase one exploration program within the area governed by PPL 474, 475, 476 and 477 (previously PPL 236, 237 and 238) is nil (Dec 2013 - nil, Dec 2012 - $1,384,492). This balance is based on the initial liability recognized in 2006 of $3,588,560 relating to its obligation to drill the four exploration wells on behalf of the investors, being reduced by amounts already incurred in fulfilling the obligation. During the year ended December 31, 2013, the remaining balance of this obligation was allocated against the costs incurred during the year on preparatory work on two exploration wells. PNGDV has a 6.75% interest in the four exploration wells.

PNGDV also has the right to participate in the 16 wells that follow the first four mentioned above up to an interest of 5.75% at a cost of $112,500 per 1% per well (with higher amounts to be paid if the depth exceed 3,500 meters and the cost exceeds $8,500,000). During the year 2014, they have elected to participate in the Raptor work program, being the first of the sixteen wells that they have the right to participate.

(c) PNG Energy Investors

On October 24, 2013, the Company entered into an Exchange Agreement with PNGEI to buy back their 4.25% indirect participation interest percentage under the Amended IPI Agreement dated May 12, 2004, including their interest and rights to future distributions in exchange for 100,000 common shares of the Company, valued at $6,837,000. The full amount of this settlement has been recognized as an expense and is included under ‘exploration costs’ in the consolidated income statement.

15.

Contributions from joint venture partner

On July 27, 2012, the Company executed a farm in agreement with Pacific Rubiales Energy Corp. (“PRE”) for PRE to be able to earn a 10.0% net (12.9% gross) participating interest in the PPL (“Petroleum Prospecting License”) 237 (now reissued as PPL 475) onshore Papua New Guinea, including the Triceratops structure located within that license. PRE's gross participating interest will be subject to the Government of Papua New Guinea's back-in rights provided for in relevant PNG legislation. Additionally, PRE has the option to terminate the Farm-In Agreement at various stages of the work program and to be reimbursed up to US$96.0 million of the $116.0 million initial cash payment (which does not include carried costs) out of future upstream production proceeds.

Consolidated Financial Statements INTEROIL CORPORATION 45

InterOil Corporation

Notes to Consolidated Financial Statements

(Expressed in United States dollars)

15.

Contributions from joint venture partner (cont’d)

Pacific LNG Operations Ltd., an affiliate of Clarion Finanz A.G., and its affiliates (“PacLNG”) are participating on a 25% beneficial equity basis in the portion of the farm-in transaction relating to the Triceratops structure (2.5% net and 3.2% gross participating interest), by reducing PacLNG’s indirect participating interest in the Triceratops structure. As a result, PacLNG will receive credits for 25% of the payments PRE makes under the farm-in transaction relating to the Triceratops structure, which will be adjusted against their cash calls receivable balance. PacLNG also received a commission fee of 2.5% of resource payments made by Pacific Rubiales (other than carried costs). Certain other indirect participating interest holders have also elected to participate in the farm-in transaction and are therefore also entitled to credits for 5.108116% of the payments PRE makes under the farm-in transaction relating to the Triceratops structure, which will also be adjusted against their cash calls receivable balance. Amounts paid to PacLNG (including commission fee) or other indirect participating interest holders as part of this transaction will be reimbursable back to the Company (under same terms as reimbursable to PRE) if PRE exercises its option to terminate the Farm-In Agreement at any stage of the work program.

As at December 31, 2014, PRE has paid the full amount of the staged cash payments of $116.0 million. Based on the company’s disclosed policy on successful efforts accounting for oil and gas properties and accounting guidance under ASC 932-360, as the payment of $20.0 million is non-refundable, conveyance accounting was applied to this payment during the year ended December 31, 2012. The remaining $96.0 million is refundable if PRE decides to exit the program or the agreement is not completed, hence conveyance accounting has not been triggered on this payment. As such, cash payments received under the Initial Cash Payment are to be retained on the balance sheet as a long-term liability until the Initial Resource Payment has been received, at which time management expects the conveyance to be triggered on these payments. The Initial Resource Payment is payable by PRE within one month after a discovery in Triceratops is considered to be commercial and the necessary resource certifications have been obtained.

The credit of $27.3 million due to PacLNG and other indirect participating interest holders as a result of the Initial Cash Payment of $96.0 million has been adjusted against their cash calls receivable balance. In addition, the 2.5% commission payable to PacLNG of $2.4 million has been paid to PacLNG during the quarter ended June 30, 2013. However, as the $96.0 million is potentially refundable to PRE if they decide to exit the program, the $27.3 million credit allocated to PacLNG and other indirect participating interest holders and the 2.5% commission payable to PacLNG are also refundable from PacLNG and have therefore been recognized as a non-current receivable.

16.

Share capital and reserves

The authorized share capital of the Company consists of an unlimited number of common shares with no par value and an unlimited number of preferred shares, of which 1,035,554 series A preferred shares are authorized. Each common share entitles the holder to one vote.

(a)

Common shares - Changes to issued share capital were as follows:

	Number of shares			$

January 1, 2012		48,121,071			905,981,614

Shares issued on exercise of options under Stock Incentive Plan		411,760			18,860,865
Shares issued on vesting of restricted stock units under Stock Incentive Plan		74,567			3,817,277

December 31, 2012		48,607,398			928,659,756

Shares issued on exercise of options under Stock Incentive Plan		408,667			11,329,836
Shares issued on vesting of restricted stock units under Stock Incentive Plan		101,177			7,055,681
Shares issued on buyback of PNGEI interest		100,000			6,837,000

December 31, 2013		49,217,242			953,882,273

Shares issued on exercise of options under Stock Incentive Plan		127,400			3,623,272
Shares issued on vesting of restricted stock units under Stock Incentive Plan		111,505			7,283,299
Shares issued on buyback of IPI interest in PRL 15 (note 14)		688,654			41,525,728
Shares buyback		(730,000	)		(14,620,792	)

December 31,2014		49,414,801			991,693,780

Consolidated Financial Statements INTEROIL CORPORATION 46

InterOil Corporation

Notes to Consolidated Financial Statements

(Expressed in United States dollars)

16.

Share capital and reserves (cont’d)

During the year ended December 31, 2014, the Company redeemed 730,000 common shares through market purchases at a weighted-average price of $57.16. The total purchase price of the buyback was $41,753,893. All shares purchased by the Company were cancelled. The Company’s share capital was reduced by an amount equal to the carrying value of the redeemed shares. The remainder was recorded as a reduction to contributed surplus of $8,077,658, being the excess contributed surplus balance excluding the value of any outstanding share compensation related to employee stock options and restricted stock; and a reduction to retained earnings of $19,055,444 on the consolidated statement of changes in equity.

(b) Preferred shares - No preferred shares are issued, or were issued at any time during the year ended December 31, 2014 (Dec 2013 – nil, Dec 2012 - nil).

(c) Nature and purpose of reserves

Foreign currency translation reserve: Exchange differences arising on translation of foreign controlled entities are recognized in other comprehensive income and accumulated in a separate reserve within equity. The cumulative amount has been reclassified to profit or loss on the disposal of the downstream assets to Puma during the year 2014.

Available-for-sale financial assets: Changes in the fair value and exchange differences arising on translation of investments, such as equities classified as available-for-sale financial assets, are recognized in other comprehensive income and accumulated in a separate reserve within equity. Amounts are reclassified to profit or loss when the associated assets are sold or impaired.

Conversion options: This reserve was used to recognize the value of the conversion option included in the agreement with IPI investors (refer to note 14). This balance was transferred to contributed surplus in the year ended December 31, 2013 as none of the IPI investors had any conversion rights outstanding.

Contributed surplus: The contributed surplus reserve is used to recognize the fair market value of employee stock options and restricted stock units that have not been forfeited or been exercised. In addition, when IPI investors waive their conversion options, the balance in the conversion options equity account is transferred to contributed surplus.

17.

2.75% convertible notes

On November 10, 2010, the Company completed the issue of $70,000,000 unsecured 2.75% convertible notes with a maturity of five years. The note holders have the right to convert their note into common shares at any time at a conversion rate of 10.4575 common shares per $1,000 principal amount of notes (which results in an effective initial conversion price of approximately $95.625 per share). The Company has the right to redeem the notes if the daily closing sale price of the common shares has been at least 125% of the conversion price then in effect for at least 15 trading days during any 20 consecutive trading day period. Accrued interest on these notes is to be paid semi-annually in arrears, in May and November of each year, commencing May 2011.

The liability component on initial recognition after adjusting for the underwriting placement fee and transaction costs amounted to $51,992,857 and the equity component amounted to $14,298,036. The liability component will be accreted over the five year maturity period to bring the liability back to the carrying value. During the year ended December 31, 2013, $2,000 of notes was converted in exchange for cash, leaving $69,998,000 of convertible notes outstanding at December 31, 2013 and 2014.

The accretion expense relating to the note liability for the year ended December 31, 2014 was $3,839,366 (Dec 2013 - $3,617,760, Dec 2012 - $3,408,951) and the cumulative accretion expenses incurred since inception was $14,510,682. The liability component at inception of $51,992,857 combined with the cumulative accretion of $14,510,682, less $1,545 being the debt component of the $2,000 of notes converted in 2013 results in the year end December 31, 2014 liability balance of $66,501,994. The equity component at inception of $14,298,036 less $409 being the equity component of $2,000 notes converted in 2013 results in the year ended December 31, 2014 equity balance of $14,297,627.

In addition to the accretion, interest at 2.75% per annum has been expensed for the year ended December 31, 2014 amounting to $1,924,945 (Dec 2013 - $1,924,959, Dec 2012 - $1,925,000). The interest payable up to November 2014 was paid in cash.

Consolidated Financial Statements INTEROIL CORPORATION 47

InterOil Corporation

Notes to Consolidated Financial Statements

(Expressed in United States dollars)

18.

Stock compensation

(a) Stock options

Options are issued at no less than market price to directors, certain employees and to a limited number of contractor personnel. Options are exercisable for common shares on a 1:1 basis. Individuals are granted options which only vest if certain performance standards are met, with the vesting of the majority of options issued only being reliant on the individual remaining employed with the Company for a certain time period, while the vesting of some options granted are reliant on various performance conditions. Options vest at various dates in accordance with the applicable individual option agreements, vesting generally between one to four years after the date of grant, have an exercise period of three to five years after the date of grant, and are subject to the option plan rules. Upon resignation or retirement, vested options must generally be exercised within 90 days or before expiry of the options if this occurs earlier.

	December 31, 2014						December 31, 2013						December 31, 2012
Stock options outstanding	Number of options			Weighted average exercise price $			Number of options			Weighted average exercise price $			Number of options			Weighted average exercise price $
Outstanding at beginning of period		507,400			49.46			1,066,067			36.20			1,487,827			30.97
Granted		30,000			56.88			90,000			71.07			90,000			57.24
Exercised		(127,400	)		(17.16	)		(408,667	)		(16.74	)		(411,760	)		(28.32	)
Forfeited		-			-			(240,000	)		(54.39	)		(100,000	)		(9.80	)
Expired		-			-			-			-			-			-
Outstanding at end of period		410,000			60.03			507,400			49.46			1,066,067			36.20

At December 31, 2014, in addition to the options outstanding as per the above table, there were an additional 1,034,832 (2013 – 1,146,842, 2012 – 1,101,357) common shares reserved for issuance under the Company’s 2009 stock incentive plan as approved on June 19, 2009.

Options issued and outstanding							Options exercisable
Range of exercise prices $	Number of options		Weighted average exercise price $		Weighted average remaining term (years)		Number of options		Weighted average exercise price $
41.01 to 51.00		15,000		50.70		4.32		15,000		50.70
51.01 to 61.00		230,000		53.34		0.70		30,000		57.24
61.01 to 71.00		45,000		65.40		1.82		45,000		65.40
71.01 to 81.00		120,000		72.01		2.82		60,000		76.28
		410,000		60.03		1.69		150,000		66.65

Aggregate intrinsic value of the 410,000 options issued and outstanding as at December 31, 2014 is $14,813,931. Aggregate intrinsic value of 150,000 options exercisable as at December 31, 2014 is $6,115,812. The weighted-average grant-date fair value of options granted during 2014 was $40.20 (2013 - $41.77, 2012 - $36.30). The total intrinsic value of options exercised during the year ended December 31, 2014 was $1,436,582 (2013 - $4,489,908, 2012 - $7,197,804). Cash received from option exercise under all share-based payment arrangements for the year ended December 31, 2014 was $2,186,690 (2013 - $6,839,928, 2012 - $11,663,059). The weighted-average share price at the date of exercise of options exercised during the year ended December 31, 2014 was $48.49 (2013 - $81.77, 2012 - $74.95).

The fair value of the 30,000 (2013 – 90,000, 2012 – 90,000) options granted during the year ended December 31, 2014 has been estimated at the date of grant in the amount of $1,206,094 (2013 - $3,759,178, 2012 - $3,267,229) using a Black-Scholes pricing model. The current year compensation expense of $2,740,367 (2013 – negative $3,154,490, 2012 – $2,903,133) was adjusted against contributed surplus under equity and $1,436,582 (2013 - $4,489,908, 2012 - $7,197,804) was transferred to share capital on exercise of options, leaving a net impact of $1,303,785 (2013 – negative expense of $7,644,398, 2012 – negative expense of $4,294,671) on contributed surplus.

Consolidated Financial Statements INTEROIL CORPORATION 48

InterOil Corporation

Notes to Consolidated Financial Statements

(Expressed in United States dollars)

18.

Stock compensation (cont’d)

The assumptions contained in the Black Scholes pricing model are as follows:

Year		Period	Risk free interest rate (%)		Dividend yield		Volatility (%)		Weighted average expected life for options
	2014	Jan 1 to Dec 31		0.9		-		65		10.0
	2013	Jul 1 to Dec 31		0.6		-		73		5.0
	2013	Jan 1 to Jun 30		0.4		-		73		5.0
	2012	Jan 1 to Dec 31		0.5		-		80		5.0

The expected volatility used in the Black Scholes pricing model has been based on historical volatility of the Company’s common shares for the period based on the expected life of the options.

(b) Restricted stock

Restricted stock may be issued to directors, certain employees and to a limited number of contractor personnel under the Company’s 2009 stock incentive plan. Restricted stock vests at various dates in accordance with the applicable restricted stock agreement, vesting generally between one to three years after the date of grant.

	December 31, 2014						December 31, 2013						December 31, 2012
Restricted stock units outstanding	Number of restricted stock units			Weighted Average Grant Date Fair Value per restricted stock unit $			Number of restricted stock units			Weighted Average Grant Date Fair Value per restricted stock unit $			Number of restricted stock units			Weighted Average Grant Date Fair Value per restricted stock unit $
Outstanding at beginning of period		145,668			66.97			153,484			63.89			152,190			61.54
Granted		89,437			59.58			120,378			75.70			97,850			57.16
Exercised		(128,150	)		(64.74	)		(112,331	)		(70.24	)		(83,880	)		(53.07	)
Forfeited		(7,427	)		(67.76	)		(15,863	)		(70.99	)		(12,676	)		(66.86	)
Expired		-			-			-			-			-			-
Total		99,528			63.68			145,668			66.97			153,484			63.89

The current year compensation expense of $6,922,035 (2013 - $7,925,461, 2012 - $4,978,933) was adjusted against contributed surplus under equity and $8,295,983 (2013 - $7,890,213, 2012 - $4,451,655) was transferred to share capital on vesting of stock units, leaving a net impact of $1,373,947 (2013 - $35,248, 2012 - $527,278) on contributed surplus.

19.

Interest revenue

	Year ended
	December 31,			December 31,		December 31,
	2014			2013		2012
	$			$		$

Interest income on short term deposits		1,371,284			70,675		62,013
Interest accretion income on receivable from Total (note 8)		24,826,440			-		-
Adjustment due to change in timing of estimated cash flows on receivable from Total (note 8)		(24,206,783	)		-		-
Interest revenue		1,990,941			70,675		62,013

Consolidated Financial Statements INTEROIL CORPORATION 49

InterOil Corporation

Notes to Consolidated Financial Statements

(Expressed in United States dollars)

20.

Finance costs

	Year ended
	December 31,		December 31,		December 31,
	2014		2013		2012
	$		$		$

Interest expense on Credit Suisse Secured Loan		4,303,388		471,201		-
Interest expense on Westpac and BSP Secured Loan		1,341,127		1,035,106		-
Interest expense on Mitsui Unsecured Loan		-		1,298,363		749,033
Interest expense on Convertible Notes		1,924,945		1,924,959		1,925,000
Interest accretion on Convertible Notes		3,839,366		3,617,760		3,408,951
Financing fees on Credit Suisse Secured Loan		16,850,197		3,527,796		-
Financing fees on Westpac and BSP Secured Loan		1,172,534		1,158,422		-
Other finance costs		555,504		93,081		104,508
Finance costs		29,987,061		13,126,688		6,187,492

21.

Australian office closure

During the year ended December 31, 2014, the Company completed the closure of its Australian office and the transition of the functions performed by that office to its PNG and Singapore offices. The Company incurred $12.0 million during the year ended December 31, 2014 on the completion of this restructuring, which is included in administrative and general expenses and legal and professional fees in the consolidated income statement.

22.

Earnings/(loss) per share

Conversion options, convertible notes, stock options and restricted stock units totaling 1,241,532 common shares at prices ranging from $50.70 to $95.63 were outstanding as at December 31, 2014 and some were included in the computation of the diluted earnings per share from continuing operations for the year ended December 31, 2014. However, the diluted instruments were not included in the computation of the diluted loss per share from continuing operations in the years ended December 31, 2013 and December 31, 2012 because they caused the loss per share to be anti-dilutive.

Potential dilutive instruments outstanding	Number of shares December 31, 2014		Number of shares December 31, 2013		Number of shares December 31, 2012
Employee stock options		410,000		507,400		1,066,067
Employee Restricted Stock		99,528		145,668		153,484
IPI Indirect Participation interest - conversion options		-		-		140,480
2.75% Convertible notes		732,004		732,004		732,025
Total stock options/shares outstanding		1,241,532		1,385,072		2,092,056

The income available to the common shareholders and the income available to the dilutive holders, used in the calculation of the numerator in the EPS calculation for the year ended December 31, 2014, December 31, 2013 and 2012 is the net profit/loss from continuing operations as per the Consolidated Income Statement. This is due to the fact that the inclusion of convertible securities in the calculation would result in the EPS being anti-dilutive.

The reconciliation between the ‘Basic’ and ‘Basic and Diluted’ shares, used in the calculation of the denominator in the EPS calculation is as follows:

Consolidated Financial Statements INTEROIL CORPORATION 50

InterOil Corporation

Notes to Consolidated Financial Statements

(Expressed in United States dollars)

22.

Earnings/(loss) per share (cont’d)

	Year ended
	December 31,		December 31,		December 31,
	2014		2013		2012
	$		$		$

Basic		49,619,048		48,793,986		48,352,822
Employee stock options		22,559		-		-
Employee restricted stock		86,609		-		-
Diluted		49,728,216		48,793,986		48,352,822

23.

Investment Accounted for using the Equity Method

The Company’s interest in PNG LNG Inc. is governed by a Shareholders’ Agreement signed on July 30, 2007 between InterOil LNG Holdings Inc., a wholly-owned subsidiary of InterOil, and PacLNG. PNG LNG Inc. is resident in The Bahamas with subsidiaries resident in PNG and Australia, the principal activity of which is the previously proposed joint venture of the development of an LNG plant in PNG.

As at December 31, 2014, InterOil LNG Holdings Inc. holds 77.165% of the ‘B’ Class shares of PNG LNG Inc. However, InterOil LNG Holdings Inc. holds 52.5% economic interest in the LNG project, subject to the exercise of PacLNG’s rights to the ‘B’ Class shares on payment of cash calls.

As a result of the adoption of IFRS 11, effective January 1, 2013, the Company reclassified its involvement with PNG LNG Inc. from a jointly controlled entity to a joint venture. The Company assessed its interest in the joint arrangement as a joint venture as the assets and liabilities held in PNG LNG Inc. and its subsidiaries are the assets and liabilities of those entities and not the assets and liabilities of the parties to the joint arrangement. The separate vehicle was to be considered in its own right and as such the PNG LNG joint arrangement was considered to be a joint venture. In addition, under the agreement, both parties had joint control of the arrangement as decisions about the relevant activities of the arrangement required the unanimous consent of the parties sharing control, further indicating that the joint arrangement was a joint venture. The Company’s interests in PNG LNG Inc. was accounted for using the equity method of accounting.

On August 6, 2013, the Company entered into an agreement with PacLNG in relation to their interest in the PNG LNG joint venture whereby their interest was aligned with the interest they have in the Upstream operations of the Company, and their share of historical joint venture costs was accepted and settled. In effecting the terms of this agreement, PacLNG will be issued 185,286 ‘B’ Class shares in the joint venture and a net 3,565,300 shares on issue to the Company are to be cancelled. Following the alignment, the Company’s interest in the joint venture is 77.165% and PacLNG’s interest is 22.835%.

To date the Company had recognized a deferred gain of $9,566,992 on its contributions to PNG LNG Inc. arising from the initial contribution of assets to the joint venture which did not have a reliably measurable fair value. This deferred gain may increase/decrease as the other joint venture partners decrease/increase their shareholding in the project. This gain on contributions have been deferred as the JV had not reached the Final Investment Decision (FID), received approvals from the Government of Papua New Guinea or achieved the intended structure of JV.

The transaction on August 6, 2013 reduced the Company’s interests in PNG LNG from 84.582% (Dec 2012) to 77.165%, but increased the Company’s share of the net assets of the joint venture from $9,922,089 to $27,124,830. Consequently the Company recognized a gain on the transaction of $2,619,420 and the carrying amount of the investment in PNG LNG increased from a net deferred gain balance of $9,222,089 as December 31, 2012 (Dec 2011 - $10,412,275) to an investment balance of $17,557,838 at December 31, 2013.

As the original intention of the joint venture was the development of an LNG plant in PNG with PacLNG, the Company is now progressing the LNG Project development jointly with Total S.A, hence the assets within the joint venture were assessed for impairment at December 31, 2014 and as a result, an impairment loss was recognized by the joint venture, with a corresponding impact on the Company’s interest in the joint venture. However, the Company’s share of losses in the joint venture exceeded the Company’s interest in the joint venture and therefore the Company discontinued recognizing its share of further losses of the joint venture when the Company’s interest was reduced to nil. No additional losses are provided for as the Company has no legal or constructive obligation to make payments on behalf of the joint venture for the Company’s share of unrecognized losses/liabilities. The share of losses not recognized by the Company for the year ended December 31, 2014 was $2,324,494 (2013 – nil, 2012 – nil).

Consolidated Financial Statements INTEROIL CORPORATION 51

InterOil Corporation

Notes to Consolidated Financial Statements

(Expressed in United States dollars)

23.

Interests in Joint Ventures – Equity Accounted (cont’d)

Information relating to the joint venture is set out below.

Summarized balance sheet			As at

	December 31,		December 31,		December 31,
	2014		2013		2012
	$		$		$

Current assets:
Cash and cash equivalents		124,432		124,948		164,767
Other current assets		-		-		79
Total current assets		124,432		124,948		164,846
Non-current assets:
Plant and equipment		-		-		527
Oil and gas properties		-		25,723,431		23,053,424
Total non-current assets		-		25,723,431		23,053,951
Total assets		124,432		25,848,379		23,218,797

Current liabilities:
Trade and other payables		34,274		35,820		2,025,132
Due to related parties		43,596		-		17,297,124
Total current liabilities		77,870		35,820		19,322,256
Total non-current liabilities		-		-		-
Total liabilities		77,870		35,820		19,322,256

Net assets		46,562		25,812,559		3,896,541

Summarized statement of comprehensive income	Year ended

	December 31,			December 31,			December 31,
	2014			2013			2012
	$			$			$

Interest revenue		91			370			448
Depreciation expense		-			(527	)		(9,623	)
Impairment expense		(25,723,431	)		-			-
Other expenses		(42,657	)		(410,537	)		(570,364	)
Loss from continuing operations before income taxes		(25,765,997	)		(410,694	)		(579,539	)
Income tax expense		-			-			-
Loss from continuing operations		(25,765,997	)		(410,694	)		(579,539	)
Other comprehensive (loss)/income		-			-			-
Total comprehensive (loss)/income		(25,765,997	)		(410,694	)		(579,539	)

The information above reflects the amounts presented in the financial statements of the joint venture and not the Company’s share of those amounts. The amounts have been amended to reflect adjustments made by the entity when using the equity method.

The following table provides a reconciliation of the financial information above to the carrying amount of the Company’s interest in the joint venture:

Consolidated Financial Statements INTEROIL CORPORATION 52

InterOil Corporation

Notes to Consolidated Financial Statements

(Expressed in United States dollars)

23.

Interests in Joint Ventures – Equity Accounted (cont’d)

	December 31,			December 31,			December 31,
	2014			2013			2012
	$			$			$

Opening net assets January 1		25,812,559			3,896,541			4,476,080
Loss for the period		(25,765,997	)		(410,694	)		(579,539	)
Adjustment to net assets resulting on alignment of interests		-			22,326,712			-
Other comprehensive income		-			-			-
Closing net assets		46,562			25,812,559			3,896,541

InterOil's share in %		77.165	%		77.165	%		84.582	%
InterOil's share in $		35,930			19,918,261			3,295,772
Goodwill		-			7,206,569			6,626,317
		35,930			27,124,830			9,922,089
Allocation against deferred gain on contributions		(35,930	)		(9,566,992	)		(9,922,089	)
Investment balance at period end		-			17,557,838			-

24.

Related parties

(a) Key management compensation

Key management includes directors (executive and non-executive) and executive officers. The compensation paid or payable to key management for services is shown below:

	December 31,		December 31,		December 31,
	2014		2013		2012
	$		$		$
Salaries and other short-term employee benefits		11,421,468		5,388,237		5,314,046
Post-employment benefits		-		43,621		93,110
Termination benefits		2,116,335		8,700,000		-
Share-based payments		6,047,136		1,575,420		1,439,993
Total		19,584,939		15,707,278		6,847,149

During year ended December 31, 2014, former Chief Financial Officer, Collin Visaggio, and former Chief Operating Officer, William Jasper, retired. Compensation paid or payable to these officers upon their retirement was $1.5 million and $0.65 million, respectively. During the year ended December 31, 2013, former CEO Phil Mulacek and former Executive VP Christian Vinson retired. Compensation paid or payable to these officers upon their retirement was $7.2 million and $1.5 million respectively.

(b) Phil Mulacek consultancy services

Phil Mulacek, a former director of InterOil, provided advisory services to the Company during the year ended December 31, 2013. Under the agreement with Mr. Mulacek, InterOil paid $25,000 a month for his advisory services from May 1, 2013 to December 31, 2013. Amounts paid or payable to Mr. Mulacek for the year ended December 31, 2013 amounted to $200,000. Mr. Mulacek resigned as a director of the Company on November 14, 2013.

25.

Commitments and contingencies

(a) Exploration and debt commitments

Payments due by period contractual obligations are as follows:

Consolidated Financial Statements INTEROIL CORPORATION 53

InterOil Corporation

Notes to Consolidated Financial Statements

(Expressed in United States dollars)

25.

Commitments and contingencies (cont’d)

	Total		Less than 1 year		1-2 years		2-3 years		3-4 years		4-5 years		More than 5 years
	'000		'000		'000		'000		'000		'000		'000
Petroleum prospecting and retention licenses		428,290		46,560		82,047		91,400		94,358		97,650		16,275
Convertible notes obligations		71,763		71,763		-		-		-		-		-
		500,053		118,323		82,047		91,400		94,358		97,650		16,275

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

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

The Company’s commitments of $120.0 million as a result of rig leasing contracts are included within the petroleum prospecting and retention licenses commitments above.

(b) Operating lease commitments – Company as lessee

The Company leases various commercial office properties, residential apartments, motor vehicles and office equipment under non-cancellable operating lease agreements. The remaining lease terms are between 1 and 4 years, and the majority of lease agreements are renewable at the end of the lease period at market rate.

The future aggregate minimum lease payments under non-cancellable operating leases are as follows:

	December 31,		December 31,		December 31,
	2014		2013		2012
	$		$		$
Not later than 1 year		4,026,169		15,512,578		16,252,249
Later than 1 year and not later than 5 years		1,640,762		9,715,551		8,005,845
Later than 5 years		-		2,445,040		3,123,291
Total		5,666,931		27,673,169		27,381,385

Lease payments for the year ended December 31, 2014 in the income statement amounted to $16,665,539. This amount also includes new leases and renewals of leases negotiated during the year 2014.

(c) Contingencies:

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

Oil Search Limited dispute under PRL 15 joint venture operating agreement:

On March 27, 2014 the Company received notification from Oil Search Limited of a dispute under the Joint Venture Operating Agreement relating to PRL 15 in Papua New Guinea. The dispute relates to the sale by the Company of a subsidiary, SPI (200) Limited, to Total. The entity held a 40.1% interest in PRL 15 at the time of the sale. The matter had been referred to arbitration and was heard in late November 2014 by the International Court of Arbitration (ICC). On February 10, 2015, the ICC arbitration panel delivered its award whereby the panel dismissed all claims against the Company and declared that Total is a party to the PRL 15 Joint Venture Operating Agreement.

26.

Subsequent events

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

Consolidated Financial Statements INTEROIL CORPORATION 54

Exhibit 3

InterOil Corporation
Management
Discussion and Analysis

For the year ended December 31, 2014
March 17, 2015

TABLE OF CONTENTS

FORWARD-LOOKING STATEMENTS	2
ABBREVIATIONS AND EQUIVALENCIES	3
CONVERSION	3
OIL AND GAS DISCLOSURES	4
GLOSSARY OF TERMS	4
INTRODUCTION	7
BUSINESS STRATEGY	7
OPERATIONAL HIGHLIGHTS	8
SELECTED FINANCIAL INFORMATION AND HIGHLIGHTS	12
DISCOUNTINUED OPERATIONS	19
LIQUIDITY AND CAPITAL RESOURCES	21
RISK FACTORS	26
CRITICAL ACCOUNTING ESTIMATES	26
NEW ACCOUNTING STANDARDS	27
NON-GAAP MEASURES AND RECONCILIATION	28
PUBLIC SECURITIES FILINGS	28
DISCLOSURE CONTROLS AND PROCEDURES AND INTERNAL CONTROLS OVER FINANCIAL REPORTING	29

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

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

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

Management Discussion and Analysis INTEROIL CORPORATION 1

FORWARD-LOOKING STATEMENTS

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

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;

inherent uncertainty of oil and gas exploration;

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

the difficulties with recruitment and retention of qualified personnel;

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

landowner claims and disruption;

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

the exploration and production businesses are competitive;

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

exposure to certain uninsured risks stemming from our operations;

contractual defaults;

weather conditions and unforeseen operating hazards;

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

risk of legal action against us; and

law enforcement difficulties.

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

Management Discussion and Analysis INTEROIL CORPORATION 2

Further, forward-looking statements contained in this MD&A are made as of the date hereof and, except as required by applicable law, we will not update publicly or revise any of these forward-looking statements. The forward-looking statements contained in this MD&A are expressly qualified by this cautionary statement.

ABBREVIATIONS AND EQUIVALENCIES

Abbreviations

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

Note:

(1)

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

(2)

CONVERSION

This table outlines certain standard conversions between Standard Imperial Units and the International System of Units (metric units).

Management Discussion and Analysis INTEROIL CORPORATION 3

To Convert From	To	Multiply By
mcf	cubic meters	28.317
cubic meters	cubic feet	35.315
bbls	cubic meters	0.159
cubic meters	bbls	6.289
feet	meters	0.305
meters	feet	3.281
miles	kilometers	1.609
kilometers	miles	0.621
acres	hectares	0.405
hectares	acres	2.471

OIL AND GAS DISCLOSURES

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

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

GLOSSARY OF TERMS

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

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

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

“Board” means the board of directors of InterOil.

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

“BSP” means Bank of South Pacific Limited.

“CBA” means Commonwealth Bank of Australia.

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

Management Discussion and Analysis INTEROIL CORPORATION 4

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

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

“Credit Suisse” means Credit Suisse A.G.

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

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

“FID” means final investment decision.

“GAAP” means Canadian generally accepted accounting principles.

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

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

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

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

“JVOA” means Joint Venture Operating Agreement.

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

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

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

“Macquarie” means Macquarie Group Limited.

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

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

Management Discussion and Analysis INTEROIL CORPORATION 5

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

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

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

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

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

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

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

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

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

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

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

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

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

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

“SocGen” means Societe Generale Hong Kong branch.

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

“Tcfe” means trillion standard cubic feet equivalent.

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

Management Discussion and Analysis INTEROIL CORPORATION 6

“UBS” means UBS A.G.

“USD” means United States dollars.

“Westpac” means Westpac Bank PNG Limited.

INTRODUCTION

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

BUSINESS STRATEGY

Continue to develop as a prudent and responsible business operator;

Enable our discovered resources with strategic joint venture partners;

Maximize the value of our exploration assets; and

Position for long-term success.

Further details of our business strategy can be found under the heading “Business Strategy” in our 2014 AIF available at www.sedar.com.

Management Discussion and Analysis INTEROIL CORPORATION 7

OPERATIONAL HIGHLIGHTS

Summary of operational highlights

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

New license applications

Airborne Field Survey

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

Seismic

In 2014, we acquired seismic data across a number of leads during the Zebra seismic program targeting PPL 476 and across the Antelope field in PRL 15 during the Antelope South (formerly Antelope Deep) seismic appraisal program. We also commenced a geophysical survey (Magnetotellurics) over the Antelope field in PRL 15, Antelope South prospect in PRL 15 with survey extensions into PPL 476, and Mule Deer lead in PPL 475.

Exploration program and appraisal drilling

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

PPL 474 - Wahoo drilling program

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

We intend to resume operations following a detailed review of well engineering, equipment, options, and regulatory approval of our revised plans. We currently expect to recommence drilling in 2015.

Management Discussion and Analysis INTEROIL CORPORATION 8

PPL 475 – Raptor drilling program

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

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

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

PPL 476 – Bobcat drilling program

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

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

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

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

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

PRL15 – Total SSA

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

Management Discussion and Analysis INTEROIL CORPORATION 9

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

PRL 39 – Triceratops-3 appraisal well

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

Pacific Rubiales Energy farm-in

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

Sale of refinery and distribution assets

On June 30, 2014, we completed the Puma Transaction for gross proceeds of $525.6 million, and made a gain on the Puma Transaction of $49.5 million. The subsidiaries sold pursuant to the Puma Transaction were previously included within the Midstream Refining and Downstream segments respectively. In addition, the shipping business which was previously included within the Corporate segment has been transferred to Puma. Following the Puma Transaction, the results of these operations have been classified as ‘discontinued operations’ and we are no longer organized as separate segments for reporting purposes. The continuing operations are considered to be an Upstream Exploration and Production business.

Management Discussion and Analysis INTEROIL CORPORATION 10

Financing

On June 17, 2014, we replaced our $250.0 million facility with a $300.0 million syndicated, senior secured capital expenditure facility through a consortium of banks led by Credit Suisse. CBA, ANZ, UBS, Macquarie, BSP, BNP and Westpac, each of which was a participating lender under the original facility, in addition to new banks, MUFG and SocGen, support the new facility. Subsequent to the year end, on March 17, 2015, we signed an amendment to further extend the maturity date on this facility to the end of 2016 with Credit Suisse, CBA, ANZ, UBS AG, Macquarie, BSP, Westpac, MUFG and SocGen participating in the extension.

Other matters

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

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

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

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

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

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

Management Discussion and Analysis INTEROIL CORPORATION 11

SELECTED FINANCIAL INFORMATION AND HIGHLIGHTS

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

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

Notes:

(1)

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

Management Discussion and Analysis INTEROIL CORPORATION 12

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

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

Variance in Total Assets:

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

$286.5 million increase in cash and cash equivalents and restricted cash, mainly due to the receipt of net proceeds from the Puma Transaction, receipt of the completion payment in relation to the Total SSA, offset by expenditure on appraisal and exploration of our licenses, repayment of secured term loan facilities, and the redemption of our shares during the year ended December 31, 2014; and

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

These increases have been partially offset by:

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

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

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

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

Variance in Total Liabilities:

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

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

Management Discussion and Analysis INTEROIL CORPORATION 13

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

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

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

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

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

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

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

	*($39.4)*	*$330.1*	*Net profit/(loss) variance for the comparative periods primarily due to:*

Ø	$0.0	$340.0	Gain on conveyance of exploration and evaluation assets in relation to the completion of the Total SSA on March 26, 2014 under which Total acquired, through the purchase of all shares of a wholly owned subsidiary, a gross participating interest of 40.1275% (net 31.0988%, after the State back-in right of 22.5%) in PRL 15, which contains the Elk and Antelope gas fields.

Ø	($8.9)	$53.2	Increase in profit from discontinued operations for year ended December 31, 2014 primarily derived from the $49.5 million gain from the Puma Transaction and the profits of the operating business during the first half of 2014 prior to the Puma Transaction. Net loss from discontinued operations for the quarter ended December 31, 2014 of $1.7 million (compared to operating profit of $7.2 million in the same quarter of prior year) was mainly due to certain corporate costs incurred by us in relation to discontinued operations.

Management Discussion and Analysis INTEROIL CORPORATION 14

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

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

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

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

Management Discussion and Analysis INTEROIL CORPORATION 15

Ø	$1.3	$8.5	Increase in other revenues for the quarter predominantly resulted from recharges to Puma on certain transition services provided post divestment. Increase in other revenues for the year resulted from higher recoveries and increased utilization relating to exploration services (offset by an increase in the costs incurred by these services as a result of increased operations). Following the divestment of the operating businesses in the Puma Transaction on June 30, 2014, we have ceased to operate a shared services model that resulted in the recognition of other revenue from the internal support of the exploration and development activities. These costs have been allocated to those activities as a recovery of cost, rather than as other revenue. We are also moving to more outsourced services model with third party rigs and services rather than internally servicing the exploration and development operations.

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

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

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

As at December 31, 2014, we had cash, cash equivalents, and restricted cash of $401.7 million (December 31, 2013 - $115.2 million and December 31, 2012 - $98.7 million), of which $8.3 million (December 31, 2013 - $53.2 million and December 31, 2012 - $49.0 million) was restricted. Of the total restricted cash at December 31, 2014, $8.0 million was restricted as a debt reserve under the Credit Suisse syndicated secured loan and the balance was made up of a cash deposit on office premises and term deposits on our PPLs.

Cash flows from discontinued operations have been combined with the cash flows from continuing operations in the consolidated statements of cash flows for the quarters and years ended December 31, 2014, 2013 and 2012.

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

Management Discussion and Analysis INTEROIL CORPORATION 16

Cash flows (used in)/generated from operating activities

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

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

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

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

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

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

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

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

Cash flows generated from/(used in) investing activities

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

Management Discussion and Analysis INTEROIL CORPORATION 17

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

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

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

Ø	$0.0	$428.0	Receipt of $524.6 million gross proceeds from the Puma Transaction less $39.4 million of cash and cash equivalents held by those businesses, $52.9 million of secured loan repayments undertaken as part of the Puma Transaction, and $4.3 million of transaction costs.

Ø	$0.0	$401.3	Receipt of a $401.3 million completion payment from Total in accordance with the Total SSA during quarter ended March 31, 2014.

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

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

Ø	$67.5	$99.7	Higher cash calls and related inflows from joint venture partners relating to the receipt of funds from PRE for historical Triceratops-2 well costs, the receipt of funds from Oil Search in relation to the Tagula seismic program, and the receipt of cash calls from Total and Oil Search on PRL 15 appraisal programs.

Ø	$60.6	$118.1	Movement in non-operating working capital for the periods was primarily related to trade payables and accruals in our exploration and development operations.

Cash flows (used in)/generated from financing activities

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

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

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

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

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

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

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

Ø	$0.0	($193.0)	Drawdown of $50.0 million from the Credit Suisse syndicated secured loan facility during the quarter ended March 31, 2014 (as opposed to the $93.0 million drawdown of the Credit Suisse secured facility - net of transaction costs in year 2013) and the full loan repayment of $150.0 million in June 2014.

Ø	$0.0	($73.6)	Receipt of a $76.0 million staged cash payment from PRE for the sale of a 10.0% net (12.9% gross) participating interest in PPL 237 (now PPL 475) during the quarter ended March 31, 2013 and a $2.4 million commission was subsequently paid to PacLNG for facilitating the transaction during the quarter ended June 30, 2013.

Ø	$0.0	$78.8	Movement in utilization of the BNP working capital facility in our discontinued operations from Puma Transaction.

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

Ø	$0.0	($41.8)	During the quarter ended September 30, 2014, we redeemed 730,000 common shares with a total purchase price of $41.8 million.

Management Discussion and Analysis INTEROIL CORPORATION 18

Summary of Consolidated Quarterly Financial Results for Past Eight Quarters

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

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

(1)

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

(2)

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

DISCOUNTINUED OPERATIONS

On June 30, 2014, we completed the Puma Transaction for gross proceeds of $525.6 million, and made a gain of $49.5 million. The subsidiaries sold pursuant to the Puma Transaction were previously included within the Midstream Refining and Downstream segments respectively. In addition, the shipping business which was previously included within the Corporate segment has been transferred to Puma. Following the Puma Transaction, the results of these operations have been classified as ‘discontinued operations’ and we are no longer organized as separate segments for reporting purposes. All balance sheet items under refinery and distribution businesses were derecognized from the consolidated balance sheet as of June 30, 2014.

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

Segments		Operations

Upstream		Exploration and Development – Explore, appraise and develop hydrocarbon structures in Papua New Guinea. Proposed activities include commercializing, monetizing and developing oil and gas structures through production facilities, including a liquefied natural gas plant.

Midstream		Refining – Produce refined petroleum products at Napa Napa in Port Moresby, Papua New Guinea, for domestic and export markets.

Downstream		Wholesale and Retail Distribution – Wholesale and retail marketing and distribution of refined petroleum products in Papua New Guinea.

Corporate		Corporate – Support business segments through business development and improvement activities, general services, administration, human resources, executive management, financing and treasury, government affairs and investor relations. This segment also managed our shipping business, which operated two vessels that transport petroleum products within Papua New Guinea and the South Pacific.

Management Discussion and Analysis INTEROIL CORPORATION 19

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

($ thousands)	June 30, 2014

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

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

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

Management Discussion and Analysis INTEROIL CORPORATION 20

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

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

LIQUIDITY AND CAPITAL RESOURCES

Summary of Debt Facilities

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

Organization

Facility

Balance
outstanding
December 31,
2014

Weighted
average
interest
rate

Maturity date

Credit Suisse syndicated, senior secured capital expenditure facility

300,000,000

$Nil

Nil%

December 2015

Convertible Notes

70,000,000

69,998,000

7.91%

⁽¹⁾

November 2015

⁽¹⁾

^{Effective rate after
bifurcating the equity and debt components of the $70.0 million principal amount of 2.75%
convertible senior notes due 2015.}

Credit Suisse Syndicated Secured Loan

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

Management Discussion and Analysis INTEROIL CORPORATION 21

Unsecured 2.75% Convertible Notes

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

Other Sources of Capital

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

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

Capital Expenditure

Net expenditure on exploration and evaluation assets

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

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

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

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

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

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

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

Management Discussion and Analysis INTEROIL CORPORATION 22

Ø	($2.1)	$44.8	Costs incurred for financial advisor fees and transaction costs for the monetization of the Elk and Antelope fields.

Ø	$0.0	$41.5	Premium paid on buyback of 1.0536% indirect participation interest in PRL 15.
Ø	($1.9)	$4.9	Seismic over the Antelope field in PRL 15.

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

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

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

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

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

Ø	$2.0	$10.2	Other expenditure, including equipment purchases and a portion of Antelope-4 and Antelope-5 well costs that have been carried by Total but included in our net share of costs as the carry has been offset against the Interim Resource Payment receivable from Total.

	*$0.0*	*($611.9)*	*Allocation of costs against Total SSA proceeds*

	*$325.0*	*$325.0*	*Closing balance of exploration and evaluation assets*

Gross expenditure on exploration and evaluation assets

Gross capital expenditures on our exploration and evaluation assets in Papua New Guinea for the quarter ended December 31, 2014 was $157.7 million. Total gross expenditures for the year ended December 31, 2014 were $500.7 million.

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

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

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

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

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

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

Ø	$0.0	$44.7	Costs incurred for financial advisor fees and transaction costs for the monetization of the Elk and Antelope fields.

Ø	$0.0	$41.5	Premium paid on buyback of 1.0536% indirect participation interest in PRL 15.

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

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

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

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

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

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

Management Discussion and Analysis INTEROIL CORPORATION 23

Capital expenditure on plant and equipment

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

Capital Requirements

Existing cash balances will be sufficient to settle debt obligations and facilitate further necessary development of the Elk and Antelope fields, appraisal of Triceratops field and exploration activities planned to meet our license commitment requirements. However, oil and gas exploration and development and liquefaction are capital intensive and our business plans involve raising capital, which depends on market conditions when we raise such capital. Additionally, our joint venture share of the costs of construction of an LNG plant and other infrastructure associated with the proposed LNG plant may amount to hundreds of millions of dollars and thus exceed our existing cash balances. No assurance can be given that we will be successful in obtaining new capital on terms that are acceptable to us, particularly with market volatility.

Noted below are our contractual obligations and commitments over the next five years which are required at a minimum to maintain our licenses in good standing.

Contractual Obligations and Commitments

This table contains information on payments to meet our contracted exploration and debt obligations for each of the next five years and beyond. It should be read in conjunction with our Consolidated Financial Statements and notes thereto.

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

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

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

Off Balance Sheet Arrangements

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

Management Discussion and Analysis INTEROIL CORPORATION 24

Transactions with Related Parties

During the year ended December 31, 2014, former Chief Financial Officer, Collin Visaggio, former Chief Operating Officer, William Jasper, and former Vice President of Investor Relations, Wayne Andrews retired. Compensation paid or payable to these officers upon their retirement was $1.5 million, $0.65 million and $0.2 million respectively.

Share Capital

Our authorized share capital consists of an unlimited number of common shares and unlimited number of preferred shares, of which 1,035,554 Series A preferred shares are authorized (none of which are outstanding). As of December 31, 2014, we had 49,414,801 common shares issued and outstanding (50,656,333 common shares on a fully diluted basis) and no preferred shares issued and outstanding. The potential dilutive instruments outstanding as at December 31, 2014 included employee stock options and restricted stock in respect of 509,528 common shares and 732,004 common shares relating to the $70.0 million principal amount Convertible Notes.

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

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

INDUSTRY TRENDS AND KEY EVENTS

Financing Arrangements

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

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

Crude Prices

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

Management Discussion and Analysis INTEROIL CORPORATION 25

Exchange Rates

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

RISK FACTORS

Our business operations and financial position are subject to risks. A summary of the key risks that may affect matters addressed in this document have been included under “Forward Looking Statements” above. Detailed risk factors can be found under “Risk Factors” in our 2014 AIF available at www.sedar.com.

CRITICAL ACCOUNTING ESTIMATES

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

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

Convertible notes

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

Environmental Remediation

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

Management Discussion and Analysis INTEROIL CORPORATION 26

Share-based payments

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

Exploration and Evaluation Assets

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

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

Impairment of Long-Lived Assets

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

NEW ACCOUNTING STANDARDS

New accounting standards not yet applicable as at December 31, 2014

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

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

Management Discussion and Analysis INTEROIL CORPORATION 27

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

NON-GAAP MEASURES AND RECONCILIATION

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

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

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

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

PUBLIC SECURITIES FILINGS

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

Management Discussion and Analysis INTEROIL CORPORATION 28

DISCLOSURE CONTROLS AND PROCEDURES AND INTERNAL CONTROLS OVER FINANCIAL REPORTING

Disclosure Controls and Procedures

Our Chief Executive Officer and Chief Financial Officer have designed, or caused to be designed under their supervision, disclosure controls and procedures to provide reasonable assurance that: (i) material information relating to us is made known to our Chief Executive Officer and Chief Financial Officer by others, particularly during the period in which the annual and interim filings are being prepared; and (ii) information required to be disclosed by us in our annual filings, interim filings or other reports filed or submitted by us under securities legislation is recorded, processed, summarized and reported within the time specified in securities legislation. Such officers have evaluated, or caused to be evaluated under their supervision, the effectiveness of our disclosure controls and procedures at our financial year-end and have concluded that our disclosure controls and procedures are effective at December 31, 2014 for the foregoing purposes.

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

Internal Controls over Financial Reporting

Our Chief Executive Officer and Chief Financial Officer have designed, or caused to be designed under their supervision, internal controls over financial reporting to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of financial statements for external purposes in accordance with IFRS. Such officers have evaluated, or caused to be evaluated under their supervision, the effectiveness of our internal controls over financial reporting at our financial year-end and concluded that our internal control over financial reporting is effective, at December 31, 2014, for the foregoing purpose.

Material Changes in Internal Control over Financial Reporting

A control system, including our disclosure and internal controls and procedures, can provide only reasonable, but not absolute, assurance that the objectives of the control system will be met, no matter how well it is conceived, and it should not be expected that the disclosure and internal controls and procedures will prevent all errors or fraud.

Management Discussion and Analysis INTEROIL CORPORATION 29

Exhibit 4

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statements on Form S-8 (No. 333-162139), Form S-8 (No. 333-148673), Form S-8 (No. 333-124617), Form F-10/A (No. 333-152459), Form F-10/A (No. 333-169536), and Form F-10/A (No.333-186982) of InterOil Corporation of our report dated March 17, 2015 relating to the financial statements and the effectiveness of internal control over financial reporting, which appears in the Annual Report to Shareholders, which is Exhibit 2 to this Form 40-F.

/s/ PricewaterhouseCoopers
PricewaterhouseCoopers
Sydney, Australia
March 17, 2015

Exhibit 5

LETTER OF CONSENT

TO: UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Re: InterOil Corporation Annual Report on Form 40-F dated March 17, 2015

We are a firm of independent petroleum engineering consultants and have prepared reports dated March 13, 2015 for InterOil Corporation providing an independent resources assessment for the Elk/Antelope and Triceratops Gas Fields as at December 31, 2014 as described in the Annual Information Form (“AIF”) of InterOil Corporation dated March 17, 2015.

We hereby consent to the use to our name and report and incorporation by reference in the Registration Statements on Form S-8 (No. 333-162139), Form S-8 (No. 333-148673), Form S-8 (No. 333-124617), Form F-10/A (No. 333-152459), Form F-10/A (No. 333-169536), and Form F-10/A (No.333-186982) of InterOil Corporation of our report dated March 13, 2015, which is incorporated by reference in this Annual Report on Form 40-F dated March 17, 2015 of InterOil Corporation.

Yours truly,

GLJ PETROLEUM CONSULTANTS LTD.

/s/ Keith M. Braaten
Keith M. Braaten, P. Eng.
President and Chief Executive Officer

Calgary, Alberta
March 17, 2015

Exhibit 6

CERTIFICATIONS

I, Michael Hession, certify that:

1. I have reviewed this annual report on Form 40-F of InterOil Corporation (the “issuer”);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report;

4. The issuer’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f) for the issuer and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the issuer’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the issuer’s internal control over financial reporting that occurred during the period covered by this annual report that has materially affected, or is reasonably likely to materially affect, the issuer’s internal control over financial reporting; and

5. The issuer’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer’s auditors and the audit committee of the issuer’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer’s internal control over financial reporting.

Date: March 17, 2015	/s/ Michael Hession
	Michael Hession
	Chief Executive Officer

Exhibit 7

CERTIFICATIONS

I, Donald Spector, certify that:

1. I have reviewed this annual report on Form 40-F of InterOil Corporation (the “issuer”);

4. The issuer’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting as defined in Exchange Act Rules 13a-15(f) and 15d-15(f) for the issuer and have:

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer’s internal control over financial reporting.

Date: March 17, 2015	/s/ Donald Spector
	Donald Spector
	Chief Financial Officer

Exhibit 8

Certification Required by Rule 13a-14(b) or Rule 15d-14(b)

of the Securities Exchange Act of 1934 and

Section 1350 of Chapter 63 of Title 18 of the United States Code

In connection with the report of InterOil Corporation (the “Company”) on Form 40-F for the fiscal year ending December 31, 2014 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Michael Hession, Chief Executive Officer of the Company, certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

The information contained in this Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: March 17, 2015
	/s/ Michael Hession
	Michael Hession
	Chief Executive Officer

Exhibit 9

Certification Required by Rule 13a-14(b) or Rule 15d-14(b)

of the Securities Exchange Act of 1934 and

Section 1350 of Chapter 63 of Title 18 of the United States Code

In connection with the report of InterOil Corporation (the “Company”) on Form 40-F for the fiscal year ending December 31, 2014 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Donald Spector, Chief Financial Officer of the Company, certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

The information contained in this Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: March 17, 2015

	/s/ Donald Spector
	Donald Spector
	Chief Financial Officer

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