InterOil Corporation
Management
Discussion and Analysis

For the year ended December 31, 2013
March 31, 2014
  

TABLE OF CONTENTS
FORWARD-LOOKING STATEMENTS	2
ABBREVIATIONS AND EQUIVALENCIES	3
CONVERSION	4
OIL AND GAS DISCLOSURES	4
GLOSSARY OF TERMS	4
INTRODUCTION	8
BUSINESS STRATEGY	8
OPERATIONAL HIGHLIGHTS	9
SELECTED FINANCIAL INFORMATION AND HIGHLIGHTS	13
QUARTER AND YEAR IN REVIEW	20
LIQUIDITY AND CAPITAL RESOURCES	30
INDUSTRY TRENDS AND KEY EVENTS	40
RISK FACTORS	42
CRITICAL ACCOUNTING ESTIMATES	42
NEW ACCOUNTING STANDARDS	44
NON-GAAP MEASURES AND RECONCILIATION	45
PUBLIC SECURITIES FILINGS	46
DISCLOSURE CONTROLS AND PROCEDURES AND INTERNAL CONTROLS OVER FINANCIAL REPORTING	47

This Management Discussion and Analysis (“MD&A”) should be read in conjunction with our audited annual consolidated financial statements and accompanying notes for the year ended December 31, 2013 and our annual information form (the “2013 Annual Information Form”) for the year ended December 31, 2013. This MD&A was prepared by management and provides a review of our performance for the year ended December 31, 2013, 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.

References to “we,” “us,” “our,” “Company,” “Group”, and “InterOil” refer to InterOil Corporation or InterOil Corporation and its subsidiaries as the context requires. Information is presented as at December 31, 2013 and for the year ended December 31, 2013 unless otherwise specified. A listing of specific defined terms can be found in the “Glossary of Terms” section of this MD&A.

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FORWARD-LOOKING STATEMENTS

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

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

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

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

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

· inherent uncertainty of oil and gas exploration;

· the availability of crude feedstock at economic rates;

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

· the difficulties with recruitment and retention of qualified personnel;

· the losses from our hedging activities;

· the fluctuations in currency exchange rates;

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

· landowner claims and disruption;

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

· the inability of our refinery to operate at full capacity;

· the impact of competition;

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

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

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

· exposure to certain uninsured risks stemming from our operations;

· contractual defaults;

· interest rate risk;

· weather conditions and unforeseen operating hazards;

· general economic conditions, including further economic downturn, availability of credit, European sovereign debt-credit crisis and downgrading of United States Government debt;

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

· risk of legal action against us; and

· law enforcement difficulties.

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

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Although we believe that the assumptions underlying our forward-looking statements are reasonable, any of the assumptions could be inaccurate, and, therefore, we cannot assure you that the forward-looking statements will eventuate. In light of the significant uncertainties inherent in our forward-looking statements, the inclusion of such information should not be regarded as a representation by us or any other person that our objectives and plans will be achieved. Some of these assumptions and other risks and uncertainties that could cause actual results to differ materially from such forward-looking statements are more fully described under the heading “Risk Factors” in our 2013 Annual Information Form.

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	mm	million standard cubic feet
mbbl	thousand barrels	mmcfpd	million standard cubic feet per day
MMbbls	million barrels	mtpa	million tonnes per annum
MMboe	million barrels of oil equivalent	scfpd	standard cubic feet per day
WTI	West Texas Intermediate crude oil delivered at Cushing, Oklahoma	Tcf	trillion standard cubic feet
bscf	billion standard cubic feet	psi	pounds per square inch

Note:

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

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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

OIL AND GAS DISCLOSURES

We are required to comply with Canadian Securities Administrators’ NI 51-101, 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, 2013 in accordance with NI 51-101. This evaluation is summarized in our 2013 Annual Information Form 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, 2013.

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.

All calculations converting natural gas to crude oil equivalent have been made using a ratio of six thousand cubic feet of natural gas to one barrel of crude equivalent. Barrels of oil equivalent may be misleading, particularly if used in isolation. A barrel of oil equivalent conversion ratio of six thousand cubic feet 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.

GLOSSARY OF TERMS

“AUD” means Australian dollars.

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

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

“Board” means the board of directors of InterOil.

“BSP” means Bank of South Pacific Limited.

“CBA” means Commonwealth Bank of Australia.

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

“Consolidated Financial Statements” means the audited consolidated financial statements for the year ended December 31, 2013.

“Convertible notes” means the 2.75% convertible senior notes of InterOil due November 15, 2015.

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

“Credit Suisse” means Credit Suisse A.G.

“CRU” means catalytic reformer unit.

“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.

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

“CSP JVOA” means the Joint Venture Operating Agreement entered into with Mitsui for the proposed condensate stripping facilities, which terminated on February 28, 2013.

“CSP” or “Condensate Stripping Project” 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.

“DPE” means Department of Petroleum and Energy 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”.

“Farm-in agreement” means an agreement entered into between parties to transfer a participating interest in an oil and gas property.

“FEED” means front end engineering and design.

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

“FID” means a final investment decision. Such a decision is ordinarily the point at which a decision is made to proceed with a project and it becomes unconditional. However, in some instances the decision may be qualified by certain conditions, including being subject to necessary approvals by the State.

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

“FX” means foreign exchange.

“GAAP” means Canadian generally accepted accounting principles.

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“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.

“HOA” means Head of Agreement.

“IPI” means an indirect participation interest.

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

“LIBOR” means daily reference rate based on the interest rates at which banks borrow unsecured funds from banks in the London 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 development by us in joint venture as a non-operator of liquefaction and related facilities for the monetization of our gas discoveries.

“Macquarie” means Macquarie Group Limited.

“Marked-to-market” or “MTM” means the accounting standards of assigning a value to a position held in a financial instrument based on the current fair market price for the instrument or similar instruments.

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

“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).

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

“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.

“OPIC” means Overseas Private Investment Corporation, an agency of the United States Government.

“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.

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

“PNGDV” means PNG Drilling Ventures Limited, an entity with which we entered into an indirect participation agreement in May 2003, as amended.

“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 under the laws of British Columbia, Canada.

“PRE JVOA” means the joint venture operating agreement entered into with PRE for the sell down of PPL 237 interest.

“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.

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

“SPA” means sales and purchase agreement.

“State” means the Independent State of Papua New Guinea.

“Tcfe” means Trillion standard cubic feet equivalent.

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

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

“UBS” means UBS A.G.

“USD” means United States dollars.

“Westpac” means Westpac Bank PNG Limited.

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INTRODUCTION

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

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

Our operations are organized into four major segments:

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

BUSINESS STRATEGY

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

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

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

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

Further details of our business strategy can be found under the heading “Business Strategy” in our 2013 Annual Information Form available at www.sedar.com.

Management Discussion and Analysis   INTEROIL CORPORATION   8

OPERATIONAL HIGHLIGHTS

Summary of operational highlights

A summary of the key operational matters and events for the year, for each of the segments is as follows:

Upstream Exploration and Development

· Asset sell down

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

- The Total SPA stipulates fixed and variable resource-based payments that include $613.0 million payable on transaction completion, $112.0 million payable on FID for a new LNG plant, and $100.0 million payable at first LNG cargo from a proposed LNG facility. In addition to these fixed amounts, Total is obliged to make variable payments for resources in PRL 15 that are in excess of 3.5 Tcfe, based on certification by two independent certifiers following the drilling of up to three appraisal wells to be drilled in PRL 15. The payments for resources greater than 5.4 Tcfe will be paid at certification.

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

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

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

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

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

- Therefore, on March 26, 2014, we signed and closed with Total a revised sale and purchase agreement, under which Total acquired through the purchase of all shares in a wholly owned subsidiary, a gross 40.1275% interest in PRL 15. We retained 35.4839% of the license and immediately became entitled to receive $401.3 million for closing the transaction, receive $73.3 million on FID for an Elk and Antelope LNG project, and $65.4 million on the first LNG cargo. All fixed and variable resource-based payments that were agreed under Total SPA dated December 5, 2013 continue to apply, including those for exploration, appraisal and resource certification, and are pro-rated according to the new equity split.

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

· New license applications

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

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· Seismic and exploration program

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

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

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

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

· PRL 39

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

· 2014 Work Program

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

· $250.0 million facility

- In November 2013, we secured a $250.0 million secured syndicated capital expenditure facility, for an approved seismic data acquisition and drilling program. The facility was provided by a group of banks led by Credit Suisse and included CBA, ANZ, UBS, Macquarie, BSP, BNP Paribas and Westpac. The facility is secured by our existing exploration and corporate entities.

- The credit facility bears interest at LIBOR plus 5.5% margin on the drawn amount for the first six months. After the first six month period the margin escalates 2.0 percent every two months to a maximum of 11.5% in the last two months of the 12-month term. During the year, the weighted average interest rate was 5.65%.

- The facility must be repaid by April 30, 2014 or by completion of the Total farm-in agreement to the Elk and Antelope fields, whichever comes first. Post completion of the Total SPA on March 26, 2014, this facility is expected to be repaid in April 2014. At December 31, 2013, we had drawn down $100.0 million and the remainder was available for use according to the terms of the facility.

· PRE farm-in

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

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

· PNG Energy Investors (“PNGEI”)

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

· Condensate stripping project

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

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

Midstream – Liquefaction

· Midstream - Liquefaction Joint Venture

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

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

· Energy World Corporation

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

· FLEX LNG and Samsung

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

Midstream – Refining

· For the year ended December 31, 2013, our average daily throughput (excluding shutdown days) was 27,999 bblspd, compared to 24,483 bblspd during the year ended December 31, 2012 and 24,856 bblspd during the year ended December 31, 2011. The total number of barrels processed into product at our refinery for 2013 was 9.247 MMbbls compared with 7.426 MMbbls for 2012 and 6.730 MMbbls in 2011.

· Capacity utilization of the refinery for the year ended December 31, 2013, based on operating capacity of 36,500 bblspd, was 72% compared with 58% for year ended December 31, 2012 and 54% for year ended December 31, 2011. During the years ended December 31, 2013, 2012 and 2011, our refinery was shut down for general maintenance for 24 days, 51 days and 82 days, respectively.

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

· The PGK weakened against the USD during the year ended December 31, 2013 from 0.4755 to 0.4130, compared to the same period in 2012 when it strengthened slightly during the 12 months ended December 31, 2012 from 0.4665 to 0.4755. This weakening of the PGK, and lack of liquidity of the currency, had an unfavorable impact on the refinery results during the year ended December 31, 2013. The PGK exchange rate forms part of the ‘Import Parity Price’ formulae which is determined monthly in arrears. A rapid decline or appreciation in the PGK will affect the net result in a reporting period due to the timing difference between the set ‘Import Parity Price’ and the collection of domestic sales proceeds.

Downstream – Wholesale and Retail Distribution

· The PNG economy slowed slightly during 2013 as construction of the Exxon Mobil led LNG project neared completion. Total sales volumes for the year ended December 31, 2013 were 738.0 million litres (2012 – 752.5 million litres and 2011– 678.0 million litres), a decrease of 14.5 million litres, or 1.9% over the same period in 2012. For the quarter ended December 31, 2013, volumes were 180.3 million litres, down by 8.5 million litres or 4.5% on the corresponding quarter in 2012, the peak of construction for the LNG project.

· Our retail business accounted for approximately 14.6% of our total downstream sales in 2013 compared to 14.2% and 13.0% over the same periods in 2012 and 2011, respectively. For the quarter ended December 31, 2013, our retail business accounted for 15.3% of total volumes compared to 14.4% in the corresponding quarter of 2012.

· In 2013, we provided petroleum products to 52 retail service stations with 43 operating under our own brand, and the remainder under independent brands. Of all the service stations that we supply, we own or lease 17, which we then sub-lease to Company-approved operators. We continue to invest in new retail sites and in new retail fuel distribution systems. During the year, we re-opened two completely refurbished retail sites and purchased a key high-volume site from an independent operator. We have also planned another retail site which we expect to have completed during 2014.

· In August 2013, Westpac and BSP provided a one-year $75.0 million combined secured loan facility to be drawn in tranches of either US dollars or kina or both. Borrowings under the facility were to be used for exploration and drilling activities with $37.5 million to be available immediately and the balance to be available upon the execution of an agreement in relation to the monetization of the Elk and Antelope fields. The second tranche was cancelled after we secured a $250.0 million facility in November 2013 from banks led by Credit Suisse, and including Westpac and BSP. In addition, the Westpac-BSP loan limit was reduced to $24.8 million (PGK60.0 million) in November 2013 with the principal to be repaid in quarterly installments of PGK2.5 million starting December 31, 2013 and the balance to be repaid in the third quarter of 2014.

· In December 2013, Papua New Guinea’s Independent Competition and Consumer Commission (the “ICCC”), which regulates wholesale and retail fuel margins and prices, advised that wholesale margins would be revised for the year ended December 2014 and would apply to unleaded gasoline, diesel and kerosene.

Corporate

· On September 10, 2013, we sold our investment in FLEX LNG shares for $7.8 million, resulting in a gain on the investment for the year ended December 31, 2013 of $3.7 million.

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

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

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

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

Management Discussion and Analysis   INTEROIL CORPORATION   12

· On July 11, 2013, Dr. Michael Hession was appointed Chief Executive Officer after a long international career with BP and Woodside Energy. Dr. Hession, who was previously Senior Vice President of Woodside’s Browse LNG development, was also appointed to our Board on November 15, 2013.

· In January 2014, Jon Ozturgut was appointed Chief Operating Officer and Don Spector was appointed Chief Financial Officer. Mr. Ozturgut has more than 27 years’ international oil and gas experience with Atlantic Richfield Company, CMS Oil and Gas Company, and Woodside Energy. He replaced William J. Jasper III who retired after seven years with the Company. Mr. Spector, who has more than 35 years’ international financial experience, including 30 years in oil and gas with BP, CRA (now Rio Tinto), Woodside Energy, and the Australian Tax Office, replaced Collin Visaggio, who resigned, also after seven years with the Company.

SELECTED FINANCIAL INFORMATION AND HIGHLIGHTS

Consolidated Results for the Years Ended December 31, 2013, 2012 and 2011

Consolidated – Operating results	Year ended December 31,
($ thousands, except per share data)	2013			2012			2011
				(revised) (4)			(revised) (4)
Sales and operating revenues		1,395,699			1,308,052			1,106,534
Interest revenue		82			248			1,356
Other non-allocated revenue		4,348			12,258			11,058
Total revenue		1,400,129			1,320,558			1,118,948
Cost of sales and operating expenses		(1,259,513	)		(1,219,188	)		(1,020,932	)
Office and administration and other expenses		(59,037	)		(51,213	)		(50,169	)
Derivative (losses)/gains		(6,157	)		(4,229	)		2,006
Exploration costs		(18,794	)		(13,902	)		(18,435	)
Gain on conveyance of oil and gas properties		500			4,418			-
Gain/(loss) on Flex LNG investment		3,720			-			(3,420	)
Foreign exchange (losses)/gains		(41,210	)		(40	)		25,032
Share of net profit/(loss) of joint venture partnership accounted for using the equity method (4)		2,275			(490	)		(2,662	)
EBITDA (1)		21,913			35,914			50,368
Depreciation and amortization		(23,411	)		(21,855	)		(20,111	)
Interest expense		(18,401	)		(23,166	)		(13,333	)
(Loss)/profit before income taxes		(19,899	)		(9,107	)		16,924
Income tax (expense)/benefit		(20,459	)		10,711			736
Net (loss)/profit		(40,358	)		1,604			17,660
Net (loss)/profit per share (basic)		(0.83	)		0.03			0.37
Net (loss)/profit per share (diluted)		(0.83	)		0.03			0.36
Total assets		1,305,799			1,303,297			1,083,962
Total liabilities		572,978			527,240			324,071
Total long-term liabilities		236,741			196,029			126,962
Gross margin (2)		136,186			88,864			85,602
Cash flows generated from/(used in) operating activities (3)		70,643			(47,661	)		41,859

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   13

(2) Gross margin/(loss) is a non-GAAP measure and is “sales and operating revenues” less “cost of sales and operating expenses” and is reconciled to IFRS under the heading “Non-GAAP Measures and Reconciliation”.

(3) Refer to “Liquidity and Capital Resources – Summary of Cash Flows” for detailed cash flow analysis.

(4) Revised to effect the transition to IFRS 11 - Joint arrangements, refer to Note 2(c)(ii) of our Consolidated Financial Statements for further details. Note that the share of net loss of joint venture partnership accounted for using the equity method above consists of our share of depreciation expense incurred by the Midstream - Liquefaction joint venture, which were included in the EBITDA calculation.

Analysis of Financial Condition Comparing Years Ended December 31, 2013, 2012 and 2011

During the year ended December 31, 2013, our debt-to-capital ratio (being debt divided by [shareholders’ equity plus debt]) was 26% (19% as at December 31, 2012 and 12% as at December 31, 2011), 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 1.0 times as at December 31, 2013 (1.4 times as at December 31, 2012 and 2.2 times as at December 31, 2011). The quick ratio (or acid test ratio (being [current assets less inventories] divided by current liabilities)), which is a more conservative measure of our ability to meet short term obligations, was 0.6 times as at December 31, 2013 (0.8 times as at December 31, 2012 and 1.3 times as at December 31, 2011). The current ratio and quick ratio were below our internal targets of above 1.5 and 1.0 times respectively as at December 31, 2013. Completion of the Total SPA on March 26, 2014 is expected to bring these ratios within our internal targets.

Variance in Total Assets:

As at December 31, 2013, our total assets amounted to $1,305.8 million, compared with $1,303.3 million as at December 31, 2012, and $1,084.0 million as at December 31, 2011. This increase of $2.5 million, or 0.2%, from December 31, 2012 was primarily due to:

- $74.1 million expenditure on our oil and gas properties associated with appraisal of the Elk and Antelope fields including completion of the Antelope-3 well, preparatory work on the Elk-3 well, and Herd Base and Hou Creek infrastructure construction, PRL 15 sell down costs, and preparatory work for drilling three exploration wells within our PPL 236, PPL 237 and PPL 238 licenses;

- $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;

- $17.6 million increase in equity accounted investment in the Midstream Liquefaction joint venture due to revision in ‘IFRS 11 Joint Agreements’ which lead to a revision of our Midstream Liquefaction joint venture interests from using proportionate consolidation to equity method of accounting, and agreement with PacLNG relating to the alignment of interests in the Midstream – Liquefaction Joint Venture to those in the PRL 15; and

- $16.4 million net increase in cash and cash equivalents and restricted cash, primarily due to the $100.0 million draw down of the Credit Suisse secured loan and offset by expenditure on development of oil and gas properties.

These increases have been partially offset by:

- $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;

- $36.8 million decrease in crude and products inventory balances due to shipment timing;

- $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;

- $10.6 million decrease in plant and equipment mainly due to depreciation charges incurred during the year; and

- $4.3 million decrease in available for sale investment due to the disposal of FLEX LNG shares.

Comparing December 31, 2012 to December 31, 2011, the increase of total assets of $219.3 million or 20% was primarily due to further capitalization of expenditure of our oil and gas properties of $147.8 million associated with appraisal and development of the Elk and Antelope fields including drilling of the Antelope-3 well, preparation and drilling of the Triceratops-2 well, Herd Base and Hou Creek infrastructure construction and development expenditures on the LNG Project.

Management Discussion and Analysis   INTEROIL CORPORATION   14

Variance in Total Liabilities:

As at December 31, 2013, our total liabilities amounted to $573.0 million, compared with $527.2 million at December 31, 2012, and $324.1 million as at December 31, 2011. The increase of $45.8 million, or 9%, from December 31, 2012 was primarily due to:

- net increase of $79.6 million in secured loans payable on drawdown of the Credit Suisse secured loan of $100.0 million, and drawdown of the BSP and Westpac combined secured loan facility of $34.5 million, partially reduced by the ANZ,BNP and BSP syndicated loan repayments of $16.0 million, Westpac secured loan repayment of $12.7 million and Mitsui unsecured loan repayment of $11.9 million;

- total receipts of PRE’s $75.0 million initial staged cash payment (part of the $116.0 million initial stage cash payment) held as a liability due to its option to exit the farm-in agreement; and

- $5.1 million increase in income tax payable mainly due to profits generated in the Downstream segment during 2013.

These increases have been partially offset by:

- $57.9 million decrease in working capital facilities mainly due to discounted receivables under the BNP working capital facility now being non-recourse and no longer included within our liabilities, and timing of crude cargoes;

- $44.3 million decrease in accounts payable and accrued liabilities, mainly related to timing of payments on certain crude cargo purchases; and

- $12.1 million decrease in indirect participating interests mainly due to the allocation of indirect participating interests against exploration costs incurred during the year.

Comparing December 31, 2012 to December 31, 2011, the increase of total liabilities of $203.2 million or 63% was primarily due to a $77.8 million increase in working capital facilities for refinery; a net increase of $75.4 million in secured loans payable due to the drawdown of the $100.0 million refinery term loan facility; an increase of $21.7 million in accounts payable and accrued liabilities, mainly related to timing of payments on crude cargo purchases; and a $21.0 million increase in other non-current liabilities as a result of the receipts from the PRE transaction which are held as a liability.

Analysis of Consolidated Financial Results Comparing Years Ended December 31, 2013, 2012 and 2011

A complete discussion of each of our business segments’ results can be found under the section “Quarter and Year in Review”.

Quarterly Comparative:

Total revenues increased by $42.5 million to $398.9 million in the quarter ended December 31, 2013 from $356.4 million in the quarter ended December 31, 2012 primarily due to higher sales volumes during the quarter. The total volume of all products sold by us was 2.7 MMbbls for the quarter ended December 31, 2013, compared with 2.3 MMbbls in the corresponding quarter of 2012, mainly due to the timing of refinery exports during the current quarter ended December 31, 2013.

Our net loss for the quarter ended December 31, 2013 was $24.8 million compared with a net profit of $18.6 million for the same quarter of 2012, a decrease in profit of $43.4 million. The operating segments of Corporate, Midstream - Refining and Downstream collectively derived a net profit for the quarter of $9.2 million (2012 net profit of $32.0 million), while investments in development segments of Upstream and Midstream - Liquefaction resulted in a net loss of $34.0 million (2012 net loss of $13.5 million).

The decrease in net profit for the quarter ended December 31, 2013 was mainly due to:

- $21.0 million decrease in income tax benefits, mainly resulting from the recognition of an interest deduction arising out of the payment of interest withholding tax in November 2012 on intercompany loan interest accrued from January 2007 to October 2012; and the impact of unfavorable foreign exchange movements (weakening of the PGK against USD) affecting temporary differences on translation of the refinery nonmonetary assets using quarter-end rates;

Management Discussion and Analysis   INTEROIL CORPORATION   15

- $12.1 million increase in foreign exchange losses mainly due to the unfavorable rates from banks on transfer of PGK refinery sales proceeds to USD compared or the prior period, due to lack of liquidity of USD in Papua New Guinea, where rates fluctuate significantly based on other exporters and importers looking to convert their USD to PGK;

- $15.6 million increase in exploration costs mainly attributable to the expensing of seismic over the Bobcat and Antelope Deep (formerly Bighorn) prospects during the current quarter and 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;

- $6.8 million increase in office and administrative expenses due to amortization of financing fees incurred on the Credit Suisse led facility, and also expensing of costs associated with financing/listing options that were considered during the year;

- $3.7 million decrease in non-allocated revenue resulting from lower activities and related recoveries relating to the Upstream segment’s drilling and construction activities during the current quarter; and

- $3.4 million increase in derivative losses for commodity contracts settled during the quarter and MTM losses for outstanding commodity contracts as at December 31, 2013.

These decreases in net profit have been partly offset by:

- $12.1 million increase in gross margin on account of relatively stable crude and product prices, and higher naphtha sales with overall better crack spreads and premiums during the quarter ended December 31, 2013 as compared to the corresponding period in 2012; and

- $8.3 million reduction in interest expense, due to the interest withholding tax payment made in November 2012 on intercompany loan interest accrued from January 2007 to October 2012, partly offset by interest incurred on the refinery term loan facility and the Credit Suisse-led facility.

Annual Comparative:

Total revenues increased by $79.5 million to $1,400.1 million in the year ended December 31, 2013 from $1,320.6 million in the year ended December 31, 2012, primarily due to higher sales volumes during the year. Total revenues in the year ended December 31, 2011 were $1,118.9 million. The total volume of all products sold by us was 9.4 MMbbls for the year ended December 31, 2013, compared with 8.5 MMbls in the corresponding period in 2012, and 7.4 million barrels in 2011.

Our net loss for the year ended December 31, 2013 was $40.4 million compared with a profit of $1.6 million for the corresponding period of 2012. The operating segments of Corporate, Midstream - Refining and Downstream collectively derived a net profit for the year ended December 31, 2013 of $34.7 million (2012 net profit of $61.2 million), while investments in development segments of Upstream and Midstream - Liquefaction resulted in a net loss of $75.1 million (2012 net loss of $59.6 million).

The decrease in net profit for 2013 was primarily attributable to:

- $41.2 million increase in foreign exchange losses, resulting from the weakening of PGK against USD during the year ended December 31, 2013 (FX rate decreased from 0.4755 to 0.4130) compared to the corresponding period in 2012 (increased from 0.4665 to 0.4755), and due to unfavorable rates from banks on transferring PGK refinery sales proceeds to USD due to a lack of liquidity of USD in Papua New Guinea;

- $31.2 million decrease in income tax benefits, mainly resulting from the impact of unfavorable foreign exchange movements (weakening of PGK against USD) affecting temporary differences on translation of the refinery nonmonetary assets using year-end rates, and the recognition of an interest deduction arising out of the payment of interest withholding tax in November 2012 on intercompany loan interest accrued from January 2007 to October 2012;

- $7.8 million increase in office and administration and other expenses primarily due to higher expenses for the retirement of senior management, amortization of financing fees on the Credit Suisse-led facility, and expensing of costs associated with financing and listing options that were considered during the year;

- $7.9 million decrease in non-allocated revenues resulting from lower activities and related recoveries on the Upstream segment’s drilling and construction activities during the year; and

Management Discussion and Analysis   INTEROIL CORPORATION   16

- $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.

These decreases in net profit have been partly offset by:

- $47.3 million increase in gross margin on account of relatively stable crude and product prices during the year ended December 31, 2013 as compared to a large fall in prices during the second quarter of 2012 which resulted in a $24.6 million net realizable value write down at that time, and higher premium and better crack spread from naphtha sales during the current year; and

- $4.8 million decrease in interest expense, due to the interest withholding tax payment made in November 2012 on intercompany loan interest accrued from January 2007 to October 2012, partly offset by interest incurred on the refinery term loan facility and the Credit Suisse-led facility.

Net profit for the year ended December 31, 2012 was $1.6 million compared with $17.7 million for 2011. Main items contributing to the decrease in net profit in 2012 was the $25.1 million decrease in foreign exchange gain, due to the PGK being relatively stable in the year ended December 31, 2012 (foreign exchange rate increased from 0.4665 to 0.4755) compared to the corresponding period in 2011 when it strengthened significantly (foreign exchange rate increased from 0.3785 to 0.4665). This decrease has been partly offset by a $10.0 million increase in income tax benefits resulting mainly from the interest deductibility recognized after the payment of interest withholding tax in November 2012 on intercompany loan interest accrued from January 2007 to October 2012.

Analysis of Consolidated Cash Flows Comparing Quarters Ended December 31, 2013 and 2012, and Years Ended December 31, 2013, 2012 and 2011

As at December 31 2013, we had cash, cash equivalents, and restricted cash of $115.2 million (December 31, 2012 – $98.7 million, December 31, 2011 – $107.8 million), of which $53.2 million (December 31, 2012 - $49.0 million, December 31, 2011 - $39.3 million) was restricted. Of the total restricted cash of $53.2 million, $28.7 million (December 31, 2012 - $37.3 million, December 31, 2011 - $33.0 million) was restricted by BNP working capital facility utilization requirements; $11.2 million (December 31, 2012 - $11.3 million, December 31, 2011 - $5.9 million) was restricted as a cash deposit on the secured loans (ANZ, BSP and BNP syndicated secured loan facility as at December 31, 2013 and December 31, 2012; and OPIC facility as at December 31, 2011); $7.4 million (December 31, 2012 - $Nil, December 31, 2011 - $Nil) was restricted as a debt reserve under the Credit Suisse secured loan facility; $5.5 million (December 31, 2012 - $Nil, December 31, 2011 - $Nil) was restricted as a cash deposit securing the letter of credit issued by BNP Paribas to one of our suppliers on signing of a rig lease and services agreement; and the balance was made up of a cash deposit on office premises with term deposits on our PPLs.

Cash flows generated from/(used in) operations

Cash inflows from operations for the quarter ended December 31, 2013 were $61.1 million compared with an outflow of $19.8 million for the quarter ended December 31, 2012, a net increase in cash inflows of $80.9 million. This increase in cash inflows was mainly due to an $88.9 million net increase in working capital inflows associated with trade and other receivables, inventories and accounts payables funded mostly by our working capital facilities; partly offset by an $8.0 million decrease in net cash inflows from operations related to an increase in net losses generated by operations less any non-cash expenses.

Cash inflows from operations for the year ended December 31, 2013 were $70.6 million compared with cash outflows of $47.7 million for the year December 31, 2012, a net increase in cash inflows of $118.3 million. This increase in cash inflows was mainly due to a $106.4 million net increase in working capital inflows associated with trade and other receivables, inventories and accounts payables funded mostly by our working capital facilities; and a $11.9 million increase in net cash inflow related to the lower net loss generated by operations less any non-cash expenses for the year ended December 31, 2013.

Cash outflows from operations for the year ended December 31, 2012 were $47.6 million compared with an inflow of $41.9 million for the year ended December 31, 2011, a net increase in cash outflows of $89.5 million. This increase in cash outflows was mainly due to a $51.5 million decrease in net cash inflow generated from operations related to lower profits generated by operations less any non-cash expenses for the year ended December 31, 2012; and a $38.0 million increase in net working capital outflows associated with trade and other receivables, inventories and accounts payables.

Management Discussion and Analysis   INTEROIL CORPORATION   17

Cash flows used in investing activities

Cash outflows for investing activities for the quarter ended December 31, 2013 were $44.4 million compared with $60.2 million for the quarter ended December 31, 2012. Cash outflows for the quarter ended December 31, 2013 mainly relate to net cash expenditures on exploration, appraisal and development (net of cash calls from IPI holders) of $20.1 million; a $14.3 million increase in restricted cash held as security for various facilities; expenditures on plant and equipment of $5.9 million; and a $4.1 million decrease in working capital requirements of development segments relating to the timing of payments.

Cash outflows for investing activities for the year ended December 31, 2013 were $133.5 million compared with $157.9 million for the year ended December 31, 2012 and $180.3 million for the year ended December 31, 2011. Cash outflows for 2013 mainly relate to net cash expenditures on exploration, appraisal and development (net of cash calls from IPI holders) of $98.4 million; expenditures on plant and equipment of $26.0 million; a $12.7 million decrease in working capital requirements of development segments relating to the timing of payments; and a $4.2 million increase in restricted cash held as security for various facilities. These outflows were partially offset by $7.8 million from the sale of FLEX LNG shares (net of transaction costs).

Cash outflows for 2012 mainly relate to net cash expenditures on exploration, appraisal and development (net of cash calls from IPI holders) of $176.3 million; expenditures on plant and equipment of $30.9 million; and a $9.8 million increase in restricted cash held as security under various facilities. These outflows were partly offset by $20.0 million non-refundable initial staged cash proceeds from PRE for the sell down of a net 10.0% (12.9% gross) participating interest in PPL 237; maturity of short term PGK treasury bills of $11.8 million; and a $27.1 million increase in working capital requirements of development segments relating to the timing of payments.

Cash outflows for 2011 mainly relate to net cash expenditure on exploration, appraisal and development (net of cash calls from IPI holders) of $115.7 million; expenditure on plant and equipment of $36.9 million; acquisition of FLEX LNG shares net of transaction costs of $7.5 million; investments in short-term PGK treasury bills of $11.8 million; a $10.0 million increase in trade receivables; and a $6.7 million decrease in working capital requirements of development segments relating to the timing of receipts and payments. These outflows were partly offset by a decrease of $8.0 million in the restricted cash balance under the BNP Paribas working capital facility.

Cash flows generated from/(used in) financing activities

Cash inflows from financing activities for the quarter ended December 31, 2013 amounted to $4.8 million, compared with $72.5 million for the quarter ended December 31, 2012. Cash inflows were primarily due to the $93.0 million drawdown of the Credit Suisse secured loan facility (net of transaction costs) and the $2.8 million from issue of common shares during the quarter. These cash inflows have been partially offset by the $71.2 million net repayments of the working capital facilities; $11.1 million repayment of the BSP and Westpac secured facility; and $8.0 million repayment of the ANZ, BSP and BNP syndicated loan.

Cash inflows from financing activities for the year ended December 31, 2013 amounted to $75.1 million, compared with inflows of $185.7 million for the year ended December 31, 2012, and cash outflows of $29.4 million for the year ended December 31, 2011. Cash inflows for 2013 are primarily due to the $93.0 million drawdown of the Credit Suisse secured facility (net of transaction costs); receipt of $73.6 million initial staged cash payments from PRE for interests in PPL 237; $33.8 million net proceeds from drawdown of the BSP and Westpac combined secured facility; and $6.8 million from issuing of common shares during the year ended December 31, 2013 following the exercise of stock options. These cash inflows have been partly reduced by $57.9 million net repayments of working capital facilities; $34.4 million in full settlement with Mitsui after the termination of CSP JVOA; $16.0 million repayments of the ANZ, BSP and BNP syndicated loan; $12.9 million for full repayment of the Westpac secured loan; and $11.1 million repayments of the BSP and Westpac secured loan.

Management Discussion and Analysis   INTEROIL CORPORATION   18

Cash inflows for 2012 were primarily due to the $95.9 million drawdown of the ANZ, BSP and BNP syndicated secured loan facility (net of transaction costs); a $77.8 million increase in proceeds from the Westpac, BSP and BNP Paribas working capital facilities; receipt of $20.0 million advance payments received from PRE for the sell down of a net 10.0% (12.9% gross) participating interest in PPL 237; a $15.0 million increase from the drawdown of the Westpac secured loan facility; a $11.0 million increase in cash receipts from the exercise of stock options by employees under our stock incentive plan; and an increase of $3.6 million cash contribution from Mitsui for the CSP JVOA. These increases were partially offset by full repayment of the OPIC secured loan of $35.5 million; and semi-annual Westpac secured loan principal repayment of $2.1 million.

Cash outflows for 2011 included two repayments of the OPIC secured loan of $9.0 million and $34.8 million repayments of the working capital facility. These outflows were partly offset by $9.9 million cash contributions from Mitsui for the CSP JVOA; and $4.5 million for the issue of common shares.

Summary of Consolidated Quarterly Financial Results for Past Eight Quarters

This table contains consolidated results for the eight quarters ended December 31, 2013 by business segment, and on a consolidated basis.

Quarters ended	2013												2012
($ thousands except per share data)	Dec-31			Sep-30			Jun-30			Mar-31			Dec-31			Sep-30			Jun-30			Mar-31
Upstream		1,731			1,918			2,533			1,862			4,136			2,216			1,727			2,284
Midstream – Refining		353,749			251,725			289,300			305,172			301,925			274,671			236,006			302,310
Midstream – Liquefaction		181			-			20,089			-			-			-			-			-
Downstream		213,835			215,651			199,470			208,046			220,512			201,749			223,620			218,974
Corporate		31,832			31,714			36,201			34,923			37,552			26,880			24,742			24,757
Consolidation entries		(202,426	)		(195,773	)		(201,932	)		(199,672	)		(207,686	)		(178,652	)		(186,991	)		(210,174	)
Total revenues		398,902			305,235			345,661			350,331			356,439			326,864			299,104			338,151
Upstream		(19,974	)		(2,842	)		(19,478	)		(1,311	)		(873	)		956			(5,730	)		(6,374	)
Midstream – Refining		10,246			(3,562	)		840			12,701			12,370			13,417			(42,647	)		18,933
Midstream – Liquefaction		87			2,550			19,850			(123	)		192			11			672			(1,410	)
Downstream		14,366			14,962			7,542			10,062			12,258			9,275			11,102			21,414
Corporate		6,055			13,446			1,745			10,044			14,133			9,841			9,975			9,188
Consolidation entries		(16,082	)		(14,647	)		(11,146	)		(13,418	)		(12,199	)		(14,503	)		(9,871	)		(14,216	)
EBITDA (1)		(5,302	)		9,907			(647	)		17,955			25,881			18,997			(36,499	)		27,535
Upstream		(33,535	)		(16,206	)		(32,046	)		(13,774	)		(13,081	)		(10,936	)		(15,532	)		(17,244	)
Midstream – Refining		74			(11,074	)		(4,675	)		5,855			13,401			5,358			(32,969	)		11,320
Midstream – Liquefaction		(430	)		2,373			19,284			(681	)		(394	)		(573	)		93			(1,969	)
Downstream		9,237			9,435			4,346			6,005			7,716			5,626			6,045			13,195
Corporate		2,787			10,780			(1,701	)		7,342			10,519			7,849			8,445			6,270
Consolidation entries		(2,946	)		(1,626	)		1,562			(744	)		384			(1,988	)		2,205			(2,136	)
Net (loss)/profit		(24,813	)		(6,318	)		(13,230	)		4,003			18,545			5,336			(31,713	)		9,436
Net (loss)/profit per share (dollars)
Per Share – Basic		(0.51	)		(0.13	)		(0.27	)		0.08			0.38			0.11			(0.66	)		0.20
Per Share – Diluted		(0.51	)		(0.13	)		(0.27	)		0.08			0.38			0.11			(0.66	)		0.19

(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   19

QUARTER AND YEAR IN REVIEW

This section provides a review of the quarter and year ended December 31, 2013 for each of our business segments.

UPSTREAM – QUARTER AND YEAR IN REVIEW

Upstream – Operating results	Quarter ended December 31,						Year ended December 31,
($ thousands)	2013			2012			2013			2012
Other non-allocated revenue		683			4,136			2,621			10,363
Inter-segment revenue - Recharges		1,048			-			5,424			-
Total revenue		1,731			4,136			8,045			10,363
Office and administration and other expenses		(7,273	)		(7,274	)		(35,053	)		(11,970	)
Exploration costs		(14,830	)		758			(18,794	)		(13,902	)
Gain on conveyance of oil and gas properties		-			1,523			500			4,418
Foreign exchange gains/(losses)		398			(16	)		1,698			(930	)
EBITDA (1)		(19,974	)		(873	)		(43,604	)		(12,021	)
Depreciation and amortization		(505	)		(474	)		(2,103	)		(1,675	)
Interest expense		(13,056	)		(11,734	)		(49,854	)		(43,097	)
Loss before income taxes		(33,535	)		(13,081	)		(95,561	)		(56,793	)
Income tax expense		-			-			-			-
Net loss		(33,535	)		(13,081	)		(95,561	)		(56,793	)

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

Analysis of Upstream Financial Results Comparing the Quarters and Years Ended December 31, 2013 and 2012

This analysis outlines key movements, the net of which primarily explains the variance in results between the quarters and years ended December 31, 2013 and 2012 for certain of the line items set forth in the table above:

Quarterly Variance ($ millions)		Yearly Variance ($ millions)
	($20.5)	($38.8)	Net loss variance for the comparative periods primarily due to:
Ø	($3.5)	($7.7)	Other non-allocated revenue relates to utilization rates of construction and drilling related activities performed by us, including civil works and related infrastructure development associated with PRL 15.  Recoveries in relation to our percentage interest of the development projects are offset against relevant expenses, while recoveries of the portion relating to external party interests in the development projects are classified under other non-allocated revenue.  Reductions in other non-allocated revenue were due to lower recoveries and lower utilization relating to these activities.
Ø	$1.0	$5.4	Inter-segment revenue recharges relates to charges made to other segments for use of construction and logistics services.  No services were provided to other segments in prior periods.

Management Discussion and Analysis   INTEROIL CORPORATION   20

Ø	$0.0	($23.1)	Increase in office and administration expenses for the year was mainly due to the transfer of historical development costs for the LNG Project from the Midstream - Liquefaction segment to Upstream being the license holder of oil and gas assets in PRL 15.  This is in line with our restructuring process for the LNG project vehicles under the Midstream – Liquefaction segment.
Ø	($15.6)	($4.9)	The increase in exploration costs for the quarter and year was primarily attributable to the expensing of exploratory seismic costs, including for the Bobcat and Bighorn prospects during the quarter ended December 31, 2013; and 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.
Ø	($1.5)	($3.9)	Decrease in gain on conveyance of oil and gas properties for the quarter was mainly due to the waiver of forfeiture of 1.5% IPI interest conversion rights into common shares during the quarter ended December 31, 2012.
			Decrease in gain on conveyance of oil and gas properties for the year were mainly due to recognition of the sale of interest in PPL 237 to PRE and the waiver of forfeiture of 1.5% IPI interest conversion rights into common shares during the prior year ended December 31, 2012. During 2013, a $0.5 million gain was recognized for the waiver of a combined 1.0536% interest by investors who converted their rights of IPI into 140,480 common shares of InterOil.
Ø	$0.4	$2.6	Increase in foreign exchange gain for the year was mainly attributable to the gain on translation of the $37.5 million equivalent PGK drawdowns that were done from the combined secured loan facility with Westpac and BSP.  The weakening of the PGK against USD since the drawdowns have created translation foreign exchange gains within Upstream.  Since this facility was secured by Downstream for exploration and drilling activities undertaken by Upstream, all financing costs, interest charges, and foreign exchange exposures in relation to this facility are expensed within Upstream segment.
Ø	($1.3)	($6.8)	Higher interest expense due to increased loan balances for funding exploration and development activities provided from Corporate, Credit Suisse-led facility, and the Westpac and BSP combined secured loan facility.

Management Discussion and Analysis   INTEROIL CORPORATION   21

MIDSTREAM - REFINING – QUARTER AND YEAR IN REVIEW

Midstream Refining – Operating results	Quarter ended December 31,						Year ended December 31,
($ thousands)	2013			2012			2013			2012
External sales		185,006			131,768			561,080			445,120
Inter-segment revenue - Sales		168,544			169,183			636,682			650,805
Inter-segment revenue - Recharges		197			967			2,177			18,803
Interest and other revenue		2			7			9			185
Total segment revenue		353,749			301,925			1,199,948			1,114,913
Cost of sales and operating expenses		(322,338	)		(283,432	)		(1,127,323	)		(1,071,852	)
Office and administration and other expenses		(2,834	)		(2,811	)		(9,234	)		(28,927	)
Derivative (losses)/gains		(2,883	)		486			(6,011	)		(4,241	)
Foreign exchange losses		(15,448	)		(3,798	)		(37,152	)		(7,824	)
EBITDA (1)		10,246			12,370			20,228			2,069
Depreciation and amortization		(3,279	)		(4,153	)		(12,988	)		(12,859	)
Interest expense		(2,417	)		(11,390	)		(9,456	)		(17,825	)
Profit/(loss) before income taxes		4,550			(3,173	)		(2,216	)		(28,615	)
Income tax (expense)/benefit		(4,476	)		16,574			(7,600	)		25,722
Net profit/ (loss)		74			13,401			(9,816	)		(2,893	)
Gross Margin (2)		31,212			17,519			70,439			24,073

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

(2) Gross margin is a non-GAAP measure and is “external sales” and “inter-segment revenue – sales” less “cost of sales and operating expenses” and is reconciled to IFRS under the heading “Non-GAAP Measures and Reconciliation”.

Midstream - Refining Operating Review

	Quarter ended December 31,						Year ended December 31,
Key Refining Metric	2013			2012			2013			2012
Throughput (bblspd)(1)		28,177			26,438			27,999			24,483
Capacity utilization (based on 36,500 bblspd operating capacity)		76	%		58	%		72	%		58	%
Cost of production per barrel	$	2.98		$	3.73		$	3.38		$	4.40
Working capital financing cost per barrel of production	$	0.52		$	0.57		$	0.52		$	0.67
Distillates as percentage of production		46.3	%		47.4	%		48.7	%		55.1	%

(1) Throughput per day has been calculated excluding shut down days. During years ended December 31, 2013 and 2012, the refinery was shut down for 24 days and 51 days, respectively.

Analysis of Midstream - Refining Financial Results Comparing the Quarters and Years Ended December 31, 2013 and 2012

This analysis outlines key movements, the net of which primarily explains the variance in results between the quarters and years ended December 31, 2013 and 2012.

Management Discussion and Analysis   INTEROIL CORPORATION   22

	Quarterly Variance ($ millions)	Yearly Variance ($ millions)
	($13.3)	($6.9)	Net profit/(loss) variance for the comparative periods primarily due to:
Ø	$13.7	$46.4	Increase in gross margin for the quarter was mainly due to the following:
			+ Higher naphtha sales with overall better crack spreads and premiums; partially offset by
			- Increased premiums and freight component on the crude purchases
			Increase in gross margin for the year was mainly due to the following:
			+ Relatively stable crude and product price movement during the year ended December 31, 2013 as compared to a large fall in prices during the second quarter of 2012
			+ A $23.8 million net realizable value write down during the second quarter of 2012 while there was no inventory write down during the year ended December 31, 2013
			+ Higher naphtha sales with overall better crack spreads and premiums
Ø	($0.8)	($16.6)	Decrease in inter-segment recharges for the year was mainly due to the incorporation of our wholly-owned subsidiary, InterOil Corporate PNG Limited which began operating in October 2012 for the purpose of employing all corporate staff in Papua New Guinea, and to capture their associated costs.  In addition, this entity has taken over operation of the Napa Napa camp and all costs associated with operation of the camp are now captured in this entity.  All costs incurred by this entity are recharged to relevant InterOil entities on an equitable basis.  Corporate costs incurred for the nine months ended September 30, 2012 were captured within the Midstream - Refining segment and then recharged to other segments.
Ø	($0.0)	$19.7	Decrease in office and administrative expense for the year mainly due to costs associated with corporate employees in Papua New Guinea and operation of the Napa Napa camp which has been captured in the Corporate segment since October 1, 2012. These costs were captured within the Midstream - Refining segment in the nine months ended September 30, 2012.
Ø	($3.4)	($1.8)	Increases in derivative losses were primarily due to losses incurred from the MTM of outstanding commodity contracts as at December 31, 2013.
Ø	($11.7)	($29.3)	Increase in foreign exchange losses for the year and quarter ended December 31, 2013 was mainly due to the weakening of PGK against the USD and unfavorable rates from banks on transfer of PGK refinery sales proceeds to USD, due to lack of liquidity of USD in Papua New Guinea, where the rates fluctuate significantly based on other exporters and importers looking to convert their USD into PGK.
			The PGK fell against the USD during the year ended December 31, 2013 (FX rate decreased from 0.4755 to 0.4130) compared to the corresponding period in 2012 (FX rate increased from 0.4665 to 0.4755).

Management Discussion and Analysis   INTEROIL CORPORATION   23

		During the quarter ended December 31, 2013, the PGK-USD rate decreased from 0.4160 to 0.4130 compared to the same period in 2012 (FX rate decreased from 0.4805 to 0.4755).
$9.0	$8.4	Decreases in interest expense were mainly attributable to $9.7 million interest withholding tax paid in November 2012 for certain intercompany loan interest accrued from January 2007 to October 2012 and settled in November 2012.
($21.1)	($33.3)	Increases in future income tax expense mainly relates to income tax benefits for the prior year ended December 31, 2012 primarily due to the recognition of interest deduction arising out of the payment of interest withholding tax in November 2012 on intercompany loan interest accrued from January 2007 to October 2012; and the impact of unfavorable foreign exchange movements affecting temporary differences on translation of non-monetary assets of the refinery operation using period end rates.

MIDSTREAM - LIQUEFACTION – QUARTER AND YEAR IN REVIEW

Midstream Liquefaction – Operating results	Quarter ended December 31,						Year ended December 31,
($ thousands)	2013			2012			2013			2012
				(revised) (2)						(revised) (2)
Inter-segment revenue - Recharges		181			-			20,270			-
Total segment revenue		181			-			20,270			-
Office and administration and other expenses		(104	)		(6	)		(181	)		(45	)
Share of net profit of joint venture partnership accounted for using the equity method		10			198			2,275			(490	)
EBITDA (1)		87			192			22,364			(536	)
Interest expense		(517	)		(586	)		(1,818	)		(2,308	)
(Loss)/profit before income taxes		(430	)		(394	)		20,546			(2,843	)
Income tax expense		-			-			-			-
Net (loss)/profit		(430	)		(394	)		20,546			(2,843	)

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

(2) Revised to effect the transition to IFRS 11 - “Joint Arrangements”, refer to Note 2(c)(ii) of our Consolidated Financial Statements for further details.

Analysis of Midstream - Liquefaction Financial Results Comparing the Quarters and Years Ended December 31, 2013 and 2012

This segment’s results include our interest in the previously proposed joint venture development of the proposed midstream facilities of the LNG Project. During 2013, we have modified the direction of our midstream liquefaction business and no longer plan to be the operator of an LNG liquefaction project in which we have ownership.

In accordance with IFRS 11 - “Joint Arrangement” (which superseded IAS 31 “Interests in Joint Ventures”), we have reclassified our involvement with Midstream – Liquefaction joint venture from a jointly controlled entity to a joint venture. Our interests in Midstream – Liquefaction joint venture that were previously accounted for using the proportionate consolidation method are now accounted for using the equity method of accounting. This change of accounting method was performed retrospectively, resulting in a revision of financial results for the same period in 2012. Refer to Note 2(c)(ii) of our Condensed Consolidated Financial Statements for further details.

Management Discussion and Analysis   INTEROIL CORPORATION   24

The following analysis outlines the key movements, the net of which primarily explains the variance in results between the quarters and years ended December 31, 2013 and 2012.

Quarterly Variance ($ millions)	Yearly Variance ($ millions)
($0.0)	$23.4	Net (loss)/profit variance for the comparative periods primarily due to:
Ø $0.2	$20.3	Increase in inter-segment revenue recharges for the year was attributable to the transfer of historical development costs incurred to the Upstream segment, being the license holder of oil and gas assets in PRL 15.
Ø ($0.2)	$2.8	Increase in share of net profit of joint venture partnership accounted using the equity method for the year was mainly due to the $2.6 million profit recognized on the gain on disposal of our interest in Midstream – Liquefaction joint venture as a result of the agreement to equalize PacLNG’s interest in the joint venture to their Upstream interest in PRL 15.

DOWNSTREAM – QUARTER AND YEAR IN REVIEW

	Quarter ended						Year ended
Downstream – Operating results	December 31,						December 31,
($ thousands)	2013			2012			2013			2012
External sales		212,778			219,892			834,032			862,736
Inter-segment revenue - Sales		91			59			277			222
Interest and other revenue		966			561			2,693			1,898
Total segment revenue		213,835			220,512			837,002			864,856
Cost of sales and operating expenses		(194,743	)		(203,202	)		(771,116	)		(800,217	)
Office and administration and other expenses		(4,207	)		(4,897	)		(15,804	)		(18,815	)
Foreign exchange (losses)/gains		(519	)		(155	)		(3,154	)		8,227
EBITDA (1)		14,366			12,258			46,928			54,051
Depreciation and amortization		(1,187	)		(1,135	)		(4,821	)		(5,082	)
Interest expense		(531	)		(337	)		(1,751	)		(2,871	)
Profit before income taxes		12,648			10,786			40,356			46,098
Income tax expense		(3,411	)		(3,070	)		(11,336	)		(13,512	)
Net profit		9,237			7,716			29,020			32,586
Gross Margin (2)		18,126			16,749			63,193			62,741

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

(2) Gross margin is a non-GAAP measure and is “external sales” and “inter-segment revenue - sales” less “cost of sales and operating expenses” and is reconciled to IFRS under the heading “Non-GAAP Measures and Reconciliation”.

Management Discussion and Analysis   INTEROIL CORPORATION   25

Downstream Operating Review

	Quarter ended				Year ended
	December 31,				December 31,
Key Downstream Metrics	2013		2012		2013		2012
Sales volumes (millions of liters)		180.3		188.8		738.0		752.5
Average sales price per liter (PGK)		2.79		2.37		2.48		2.32

Analysis of Downstream Financial Results Comparing the Quarters and Years Ended December 31, 2013 and 2012

The following analysis outlines key movements, the net of which primarily explains the variance in results between the quarters and years ended December 31, 2013 and 2012.

Quarterly Variance ($ millions)	Yearly Variance ($ millions)
$1.5	($3.6)	Net profit variance for the comparative periods primarily due to:
Ø $1.4	$0.5	Increase in gross margins for the quarter was a result of increases in import parity price in October 2013 and November 2013 followed by a small import parity price decline in December 2013. This has led to higher gains on inventory holdings over this period.
Ø $0.7	$3.0	Decreases in office and administrative and other expenses were mainly due the impact of foreign exchange on mostly PGK denominated operating expenses of Downstream and reduced expenditure on repairs and maintenance.
Ø ($0.4)	($11.4)	Increase in foreign exchange losses for the year was mainly due to the weakening of PGK against the USD during the year ended December 31, 2013 and a one-time transfer of exchange gain, in the prior year, on translation of loan balances from other comprehensive income in equity to profit and loss on repayment of intercompany loans.
Ø ($0.2)	$1.1	Decrease in interest expense for the year was mainly due to lower utilization of the working capital facility during the year ended December 31, 2013.
Ø $0.3	$2.2	Decrease in income tax expense was mainly due to the lower profit before tax during the year.

Management Discussion and Analysis   INTEROIL CORPORATION   26

CORPORATE – QUARTER AND YEAR IN REVIEW

	Quarter ended						Year ended
Corporate – Operating results	December 31,						December 31,
($ thousands)	2013			2012			2013			2012
External sales		107			56			587			196
Inter-segment revenue - Sales		7,028			6,087			26,006			22,650
Inter-segment revenue - Recharges		12,233			18,838			57,561			41,905
Interest revenue		12,442			12,567			50,420			49,176
Other non-allocated revenue		22			4			95			4
Total revenue		31,832			37,552			134,669			113,931
Cost of sales and operating expenses		(5,985	)		(5,217	)		(22,056	)		(18,905	)
Office and administration and other expenses		(19,221	)		(18,138	)		(82,297	)		(52,383	)
Derivative (losses)/gains		-			(64	)		(146	)		11
Foreign exchange (losses)/gains		(571	)		-			(2,602	)		486
Gain on Flex LNG investment		-			-			3,720			-
EBITDA (1)		6,055			14,133			31,288			43,140
Depreciation and amortization		(910	)		(683	)		(3,630	)		(2,370	)
Interest expense		(1,408	)		(1,601	)		(6,931	)		(6,185	)
Profit before income taxes		3,737			11,849			20,727			34,585
Income tax expense		(950	)		(1,330	)		(1,522	)		(1,498	)
Net profit		2,787			10,519			19,205			33,087
Gross Margin (2)		1,150			926			4,537			3,941

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

(2) Gross margin is a non-GAAP measure and is “external sales” and “inter-segment revenue - sales” less “cost of sales and operating expenses” and is reconciled to IFRS under the heading “Non-GAAP Measures and Reconciliation”.

Analysis of Corporate Financial Results Comparing the Quarters and Years Ended December 31, 2013 and 2012

This analysis outlines key movements, the net of which primarily explains the variance in results between the quarters and years ended December 31, 2013 and 2012 for certain of the line items set forth in the table above.

Quarterly Variance ($ millions)	Yearly Variance ($ millions)
($7.7)	($13.9)	Net profit variance for the comparative periods primarily due to:
Ø($6.6)	$15.7	Decrease in inter-segment recharges for the quarter was due mainly to the true up of full year recharges made during the prior quarter ended December 31, 2012. Increase in inter-segment recharges for the year was mainly due to the incorporation of InterOil Corporate PNG Limited, which began operating in October 2012 for the purpose of employing all corporate staff in Papua New Guinea and to capture their associated costs. All costs incurred by this entity are recharged to relevant business segments on an equitable basis.

Management Discussion and Analysis   INTEROIL CORPORATION   27

Ø($0.1)	$1.2	Higher interest income for the year was due to an increase in inter-company loan balances.
Ø($1.1)	($29.9)	Increase in office and administrative expenses for the year was mainly due to costs associated with corporate employees in Papua New Guinea and operation of the Napa Napa camp which has been captured in the Corporate segment since October 1, 2012.  These costs were captured within the Midstream - Refining segment in the nine months ended September 30, 2012.  In addition, non-recurring expenses of $8.7 million were incurred for the retirement of senior management during the year ended December 31, 2013, amortization of financing fees for the Credit Suisse-led facility, and expensing of costs associated with financing and listing options that were considered during the year.
Ø($0.6)	($3.1)	Increases in foreign exchange losses were primarily due to the weakening of PGK against the USD and the weakening of AUD against the USD for the year ended December 31, 2013 (FX rate has decreased from 1.0383 on January 1, 2013 to 0.8873 on December 31, 2013), resulting in higher revaluation losses on monetary assets.
Ø$0.0	$3.7	Increase in gain on available-for-sale investment was due to the gain recognized for the sale of FLEX LNG shares during the year ended December 31, 2013.
Ø($0.2)	($1.3)	Increase in depreciation expense for the year was primarily due to depreciation charge for fixed assets transferred from the Refinery segment to Corporate segment in December 2012.

Management Discussion and Analysis   INTEROIL CORPORATION   28

CONSOLIDATION ADJUSTMENTS – QUARTER AND YEAR IN REVIEW

Consolidation adjustments – Operating results	Quarter ended December 31,						Year ended December 31,
($ thousands)	2013			2012			2013			2012
Inter-segment revenue - Sales		(175,665	)		(175,329	)		(662,965	)		(673,677	)
Inter-segment revenue - Recharges		(13,658	)		(19,805	)		(85,431	)		(60,707	)
Interest revenue (1)		(13,103	)		(12,552	)		(51,409	)		(49,121	)
Total revenue		(202,426	)		(207,686	)		(799,805	)		(783,505	)
Cost of sales and operating expenses (2)		172,793			175,622			660,982			671,786
Office and administration and other expenses (3)		13,551			19,865			83,532			60,930
EBITDA (4)		(16,082	)		(12,199	)		(55,291	)		(50,789	)
Depreciation and amortization (5)		33			31			130			130
Interest expense (1)		13,103			12,552			51,409			49,119
Loss before income taxes		(2,946	)		384			(3,752	)		(1,540	)
Income tax expense		-			-			-			-
Net (loss)/profit		(2,946	)		384			(3,752	)		(1,540	)
Gross Margin (6)		(2,872	)		293			(1,983	)		(1,891	)

(1) Includes the elimination of interest accrued between segments.

(2) Represents the elimination upon consolidation of our refinery sales to other segments and other minor inter-company product sales.

(3) Includes the elimination of inter-segment administration service fees.

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

(5) Represents the amortization of a portion of costs capitalized to assets on consolidation.

(6) Gross margin is a non-GAAP measure and is “inter-segment revenue elimination” less “cost of sales and operating expenses” and represents elimination upon consolidation of our refinery sales to other segments. This measure is reconciled to IFRS under the heading “Non-GAAP Measures and Reconciliation”.

Analysis of Consolidation Adjustments Comparing the Quarters and Years Ended December 31, 2013 and 2012

This table outlines key movements, the net of which primarily explains the variance in results between the quarters and years ended December 31, 2013 and 2012 for certain of the line items set forth in the table above.

	Quarterly Variance ($ millions)	Yearly Variance ($ millions)
	($3.3)	($2.2)	Net (loss)/profit variance for the comparative periods primarily due to:
Ø	($1.1)	($0.0)	Variance in net (loss)/profit for the year was due to changes in intra-group profit eliminated on consolidation relating to the Midstream Refining segment’s profit component of inventory on hand in the Downstream segment at period ends.
Ø	($2.2)	($2.2)	Variance in net loss was due to intra-Group profit eliminated on consolidation relating to the Midstream Refining segment’s land lease charges to Upstream.

Management Discussion and Analysis   INTEROIL CORPORATION   29

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, 2013.

Organization	Segment	Facility		Balance outstanding December 31, 2013			Weighted average interest rate			Maturity date
Credit Suisse Syndicated Secured Loan	Upstream	$	250,000,000	$	100,000,000			5.65	%	April 2014
ANZ, BSP and BNP syndicated secured loan facility	Midstream - Refining	$	100,000,000	$	84,000,000			6.97	%	November 2017
BNP working capital facility(1)	Midstream - Refining	$	270,000,000	$	23,941,251	(2)		3.26	%	February 2015
BNP non-recourse discounting facility(1)	Midstream - Refining	$	80,000,000	$	24,990,929	(4)		0.07	%	February 2015
Westpac PGK working capital facility	Downstream	$	18,585,000	$	9,793,577			8.67	%	November 2014
BSP PGK working capital facility	Downstream	$	18,585,000	$	2,644,203			9.45	%	November 2014
BSP and Westpac combined secured facility	Downstream	$	24,780,077	$	24,780,077			7.94	%	August 2014
2.75% convertible notes	Corporate	$	70,000,000	$	69,998,000			7.91	%(3)	November 2015

^{(1) In August 2013, the BNP Paribas working capital facility agreement with a maximum availability of $240.0 million was replaced with a new facility agreement with a maximum availability of $350.0 million (including a $30.0 million sub-limit for discounted receivables with recourse and an $80.0 million facility for non-recourse discounted receivables). Under the new 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.}

^{(2) Excludes letters of credit totaling $167.7 million, which reduces the available borrowings under the facility to $78.3 million at December 31, 2013.}

^{(3) Effective rate after bifurcating the equity and debt components of the $70.0 million principal amount of 2.75% convertible senior notes due 2015.}

^{(4) The non-recourse discounted receivables are not retained on the Company’s balance sheet as the Company does not retain the credit risk and control over these receivables.}

While cash flows from operations are expected to be sufficient to cover our operating commitments, should there be a major long term deterioration in refining or wholesale and retail margins, our operations may not generate sufficient cash flows to cover all of the interest and principal payments under our debt facilities noted above. If this were to occur, we may be forced to reduce or delay capital expenditures, sell assets, seek additional capital or restructure or refinance our indebtedness. We can provide no assurance that these alternative measures would be successful. Also, exploration and development activities require funding beyond our operational cash flows and the cash balances we currently hold. As a result, we will be required to raise additional capital and/or refinance these facilities. We can provide no assurances that we will be able to obtain such additional capital or that our lenders will agree to refinance these debt facilities, or, if available, that the terms of any such capital raising or refinancing will be acceptable to us.

Credit Suisse Syndicated Secured Loan (Upstream)

On November 11, 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.

Management Discussion and Analysis   INTEROIL CORPORATION   30

The credit facility bears interest at LIBOR plus 5.5 % margin on the drawn amount for the first six months. After the first six month period the margin escalates 2% every two months to a maximum of 11.5% in the last two months of the 12-month term. During the year, the weighted average interest rate was 5.65%.

The facility must be repaid by April 30, 2014, or by completion of the Total SPA, whichever comes first. Post completion of the Total SPA on March 26, 2014, this facility is expected to be repaid in April 2014. At December 31, 2013, we had drawn down $100.0 million and the remainder was available for use according to the terms of the facility.

ANZ, BSP and BNP Syndicated Secured Loan (Midstream- Refinery)

On October 16, 2012, we secured a five year amortizing $100.0 million syndicated secured term loan facility with BNP Paribas, BSP, and ANZ. The loan was fully drawn down in November 2012, and is secured by fixed assets of the refinery. The balance outstanding under the loan facility as at December 31, 2013 was $84.0 million. The interest rate on the loan is equal to LIBOR plus 6.5% per annum. During the year ended December 31, 2013, the weighted average interest rate under the facility was 6.97%.

The principal of the syndicated secured loan is repayable in ten half-yearly installments over the period of five years. The first four half-yearly installments are $8.0 million each, the next two installments are $10.0 million each, and the final four installments $12.0 million each. The interest payments are to be made either in quarterly or half-yearly payments, at our election, which has to be made in advance of the interest period. During the year ended December 31, 2013, we made loan repayments totaling $16.0 million. As at December 31, 2013, we have two installments of $8.0 million each due for payment on May 9, 2014 and November 9, 2014. A cash restricted balance of $11.2 million was held on deposit as at December 31, 2013 to meet our principal installment due on May 9, 2014 and interest payments on the syndicated secured loan facility.

BNP Paribas Working Capital Facility (Midstream - Refinery)

On July 17, 2013, we replaced our $240.0 million working capital facility with BNP Paribas for our Midstream – Refining operation with a $350.0 million working capital structured facility led by BNP Paribas. Out of the $350.0 million, $270.0 million is a syndicated secured working capital facility supported by BNP Paribas, ANZ, Natixis, Intesa Sanpaolo, and BSP and includes the ability for us to discount receivables with recourse up to $30.0 million. In addition, BNP Paribas has provided an $80.0 million bilateral non-recourse discounting facility. The facility is secured by our rights, title and interest in inventory and working capital of the Napa Napa refinery.

As at December 31, 2013, $191.7 million of the $270.0 million facility had been used, and the remaining $78.3 million remained available. In addition, $25.0 million of the $80.0 million non-recourse discounting facility had been used. The credit portion of the facility bears interest at LIBOR plus 3.75% per annum. The facility is renewable in February 2015.

During the year, the weighted average interest rate was 3.26% after considering the reduction in interest due to deposit amounts which reduces interest being charged.

Westpac and BSP Working Capital Facility (Downstream)

We had an approximately $57.8 million (PGK 140.0 million) combined revolving working capital facility for our Downstream operations in Papua New Guinea from BSP and Westpac. This facility was decreased in 2013 by $20.7 million (PGK 50.0 million) as a result of the new combined secured loan facility from Westpac and BSP for funding exploration and drilling activities undertaken by Upstream, reducing the limit of the Downstream working capital facility to $37.2 million (PGK 90.0 million).

The Westpac facility limit is now approximately $18.6 million (PGK 45.0 million) after being reduced in August 2013 by $18.6 million (PGK 45.0 million), and the BSP facility limit is approximately $18.6 million (PGK 45.0 million) after being reduced in November 2013 by $2.1 million (PGK 5.0 million). The facility with both banks expires in November 2014.

Management Discussion and Analysis   INTEROIL CORPORATION   31

As at December 31, 2013, $12.4 million (PGK 30.1 million) of this combined facility had been used. These facilities are secured by a fixed and floating charge over Downstream operations assets. During the year, the weighted average interest rate for the Westpac working capital facility was 8.67% and for the BSP working capital facility was 9.45%.

BSP and Westpac Combined Secured Facility (Downstream)

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

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

This facility is secured by a fixed and floating charge over Downstream operations assets. The weighted average interest rate under this facility was 7.94% for the year ended December 31, 2013.

Unsecured 2.75% Convertible Notes (Corporate)

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

We pay interest on the notes semi-annually on May 15 and November 15. 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 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 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.

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

Westpac Secured Loan (Downstream)

In February 2012, we obtained a secured loan of $15.0 million that was repayable in equal installments over 3.5 years with an interest rate of LIBOR plus 4.4% per annum. The loan was secured by a fixed and floating charge over the assets of our Downstream operations. The loan was fully repaid during the year ended December 31, 2013.

Management Discussion and Analysis   INTEROIL CORPORATION   32

Mitsui Unsecured Loan (Upstream)

On April 15, 2010, we signed preliminary joint venture and financing agreements with Mitsui for the Condensate Stripping Project that was originally aimed at accelerating revenue from the Elk and Antelope fields. On February 28, 2013, we terminated our agreements with Mitsui and on July 16, 2013, we entered into a Settlement and Termination Deed with Mitsui. In accordance with the deed, we repaid Mitsui $34.4 million for the cancellation of the option for Mitsui to acquire interests in the Elk and Antelope fields, for Mitsui’s share of costs on the project, and in repayment of an unsecured loan. The facility has now been fully repaid and all security to Mitsui has been discharged.

Other Sources of Capital

Our share of expenditures on exploration wells, appraisal wells and extended well programs is funded by capital raising activities, debt, operational cash flows, IPI holders, PNGDV, joint venture partners and asset sales.

Cash calls are made on IPI holders, PNGDV and PacLNG (for its 2.5% direct interest in the Elk and Antelope fields acquired during 2009) for their share of expenditure on appraisal wells and extended well programs where they participate under agreements we have with them. Cash calls will also be made on PRE for exploration activities in PPL 237 and appraisal activities in the Triceratops field.

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

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

On December 5, 2013, we agreed to sell to Total a gross 61.3% interest in PRL 15, which contains the Elk and Antelope gas fields in Papua New Guinea. The Total SPA covers the sale and purchase of PRL 15 interests, proposed LNG Project, and exploration farm-in rights. The Total SPA provides for fixed and variable resource-based payments, including $613.0 million to be paid to us on completion of the transaction, $112.0 million to be paid to us on FID for a new LNG plant and $100.0 million to be paid to us at first LNG cargo from the proposed LNG facility. In addition to these fixed amounts, variable payments must be made by Total for resources in PRL 15 that are in excess of 3.5 Tcfe, the value of which will depend on certification by two independent certifiers following the drilling of up to three appraisal wells in PRL 15. Completion of the Total SPA remained subject to government approval and the acquisition by us of minority interests in PRL 15. However, on February 27, 2014, Oil Search agreed to acquire shares in certain PacLNG entities that hold a 22.835% interest in PRL 15 for a consideration of $900.0 million plus further contingent payments based on resource certification. Accordingly it became impossible to fulfill one of the conditions precedent to completion of that agreement. Therefore on March 26, 2014, we signed and closed with Total a revised SPA, under which Total acquired through the purchase of all shares in a wholly owned subsidiary, a gross 40.1275% interest in PRL 15. We retained 35.4839% of the license and immediately entitled to receive $401.3 million for closing the transaction, receive $73.3 million on FID for an Elk and Antelope LNG project, and $65.4 million on the first LNG cargo. All fixed and variable resource-based payments that were agreed under Total SPA dated December 5, 2013 continue to apply, including those for exploration, appraisal and resource certification, and are pro-rated according to the new equity split.

Management Discussion and Analysis   INTEROIL CORPORATION   33

Summary of Cash Flows

	Year ended December 31,
($ thousands)	2013			2012			2011
				(revised)			(revised)
Net cash (outflows)/inflows from:
Operations		70,643			(47,661	)		41,859
Investing		(133,464	)		(157,950	)		(180,301	)
Financing		75,101			185,698			(29,413	)
Net cash movement		12,280			(19,913	)		(167,855	)
Opening cash		49,721			68,575			232,425
Exchange (losses)/gains on cash and cash equivalents		(34	)		1,059			4,005
Closing cash		61,967			49,721			68,575

Analysis of Cash Flows Generated From/(Used In) Operating Activities Comparing the Years Ended December 31, 2013 and 2012

This table outlines key variances in the cash inflows/(outflows) from operating activities between the years ended December 31, 2013 and 2012:

	Yearly variance ($ millions)
	$118.3	Variance for the comparative period primarily due to:
Ø	$11.9	Increase in cash generated from operations prior to changes in operating working capital for the year ended December 31, 2013, mainly due to the higher net loss from operations adjusted for decrease in future income tax benefit; non-cash settlement on PNGEI buyback; increase in amortization of deferred financing costs; increase in stock compensation expense; and increase in derivative losses.  These increases in cash inflows have been partly offset by the increase in gain on our FLEX LNG investment and an increase in our share of net profit of Midstream - Liquefaction joint venture.
Ø	$106.4	Increase in cash generated from operations relating to changes in operating working capital for the year.  The movement was due primarily to a $59.5 million decrease in inventories; a $22.3 million decrease in trade and other receivables; a $21.4 million increase in trade and other payables; and a $3.2 million decrease in other current assets and prepaid expenses.

Analysis of Cash Flows Used In Investing Activities Comparing the Years Ended December 31, 2013 and 2012

This table outlines key variances in cash outflows from investing activities between the years ended December 31, 2013 and 2012:

Yearly variance ($ millions)
$24.5	Variance for the comparative period primarily due to:
Ø $51.5	Lower cash outflows on exploration and development expenditures mainly due to a reduction in drilling activities.

Management Discussion and Analysis   INTEROIL CORPORATION   34

Ø $26.4	Higher cash calls and related inflows from joint venture partners relating to the Triceratops-2 well and historical infrastructure costs.
Ø $4.9	Movements in expenditure on plant and equipment were mainly within Downstream, Midstream-Refinery and Corporate segments.  The expenditures incurred during the year were mainly associated with tanks, CRU upgrades, and upgrade projects across fuel stations, terminals and depots.
Ø ($20.0)	A $20.0 million initial staged cash payment from PRE for the sell down of a net 10.0% (12.9% gross) participating interest in PPL 237 in accordance with HOA during the year ended December 31, 2012.  Subsequent payments from PRE have been classified under ‘cash flows from financing activities’ below.
Ø ($11.8)	Maturity of short term PGK Treasury bills during the year ended December 31, 2012.
Ø $7.8	Proceeds from disposal of Flex LNG shares, net of transaction costs.
Ø $5.6	Decrease in cash outflows was mainly due to a $13.0 million reduction in cash outflows in restricted cash held under BNP working capital facility and a $5.5 million decrease in cash outflows for restricted cash deposit held under ANZ, BSP and BNP syndicated loan.  These cash outflow reductions have been partially offset by a $7.4 million increase in restricted cash under debt reserve for the Credit Suisse secured loan and a $5.5 million increase in cash deposit restricted by BNP for the letter of credit issued as security for a rig lease and services agreement.
Ø ($39.9)	Movement in non-operating working capital for the year relating to trade payable and accruals in our Upstream operations.

Analysis of Cash Flows Generated From Financing Activities Comparing the Years Ended December 31, 2013 and 2012

This table outlines key variances in cash inflows from financing activities between years ended December 31, 2013 and 2012:

Yearly variance ($ millions)
($110.6)	Variance for the comparative period primarily due to:
Ø $35.5	Full repayment of OPIC loan was made in November 2012.
Ø ($38.0)	Termination settlement to Mitsui for the Condensate Stripping Project funding provided by Mitsui and related interests.
Ø ($25.7)	Full drawdown of $15.0 million Westpac secured loan during the year ended December 31, 2012 and full settlement of the outstanding secured loan from Westpac during the year ended December 31, 2013.
Ø $22.8	Drawdown of the $33.8 million secured loan facility from BSP and Westpac and partially reduced by the loan repayments of $11.1 million during the year ended December 31, 2013.
Ø $93.0	Drawdown of $100.0 million secured syndicated loan facility led by Credit Suisse AG during the quarter ended December 31, 2013 (net of transaction costs).

Management Discussion and Analysis   INTEROIL CORPORATION   35

Ø	$53.6	A $20.0 million initial staged cash payment from PRE for the sell down of 10% net (12.9% gross) interest in PPL 237 during the quarter ended September 30, 2012. During the first quarter of 2013, a total of $76.0 million staged cash payments were received from PRE in accordance with the farm-in agreement and a $2.4 million commission was subsequently paid to PacLNG for facilitating the farm-in transaction between PRE and InterOil.
Ø	($135.7)	Movement in utilization of the BNP Paribas working capital facility is due to movement in working capital requirements.
Ø	($111.9)	Drawdown of $100.0 million ANZ, BSP and BNP syndicated secured loan was made during the year ended December 31, 2012 (net of transaction costs). A total of $16.0 million semi-annual syndicated loan principal installment payments were made during the year ended December 31, 2013.
Ø	($4.2)	Movements were due to lower cash receipts from the exercise of stock options during the year ended December 31, 2013.

Capital Expenditure

Upstream Capital Expenditure

Capital expenditures for our Upstream segment in Papua New Guinea for the year ended December 31, 2013 were $74.1 million, compared with $147.8 million during the same period of 2012.

This table outlines key expenditure in the year ended December 31, 2013.

	Yearly ($ millions)
	$74.1	Expenditure in the year ended December 31, 2013 primarily due to:
Ø	$6.1	Costs for site preparation, pre-spud work and drilling at Antelope-3.
Ø	$7.1	Costs for Elk-3 well site preparation, spud works, drilling and standby works.
Ø	$4.0	Costs for road construction and maintenance from Herd Base to the Antelope field (South Road).
Ø	$1.6	Costs for wharf, camp, warehouse and related earth works at Hou Creek in PRL 15.
Ø	$4.6	Costs for road construction from Herd Base to the Antelope field (North Road) to connect the Hou Creek complex to the Antelope-2 well.
Ø	$5.3	Project management and sub-contractor costs for the LNG Project, including geotechnical and centerline pipeline surveys, pipeline FEED, and tendering for the Condensate Stripping Project.  Work on these projects has now ceased and no costs were incurred during the six months ended December 31, 2013.
Ø	$40.3	Under-recoveries for drilling services, construction equipment, labor, logistics and warehousing due to reduced activity.
Ø	$6.9	Seismic over the Triceratops field in PPL 237.
Ø	($9.5)	Allocation of historical Triceratops-2 well costs to PRE (net of credits given to other joint venture partners).
Ø	($12.9)	Allocation of historical northern infrastructure costs in the Elk and Antelope fields to joint venture partners.

Management Discussion and Analysis   INTEROIL CORPORATION   36

Ø	$12.3	Costs accrued for financial advisor fees for monetization of the Elk and Antelope fields.
Ø	$8.3	Other expenditure, including equipment purchases and drilling inventory.

Midstream – Refining Capital Expenditure

Capital expenditure totaled $5.0 million in our Midstream - Refining segment for the year ended December 31, 2013, and included upgrades to the CRU, boiler and mercury removal project.

Downstream Capital Expenditure

Capital expenditure for the Downstream segment totaled $4.7 million for the year ended December 31, 2013 and mostly involved upgrades to fuel stations, terminals and depots.

Capital Requirements

Oil and gas exploration and development, refining and liquefaction are capital intensive and our business plans involve raising capital, which depends on market conditions when we raise such capital. 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.

Most of our “net cash from operating activities” adjusted for “proceeds from/(repayments of) working capital facilities” is used in exploration programs on PPLs; and appraisal and development programs for the Elk, Antelope, and Triceratops fields in Papua New Guinea. Net cash from operating activities is not sufficient to fund those exploration, appraisal and development programs, or the construction of any new LNG plant.

Upstream

On March 6, 2014, the 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. The work program commitments under the new licenses require us to spend a total of $532.0 million over the six year term of the new licenses.

In addition, we are required to spend a further $47.1 million on development of the Elk and Antelope fields in PRL 15 by the end of 2014. All work program commitments with the exception of two wells and some additional exploration seismic, are complete. We have spent $473.8 million on PRL 15 which includes seismic, the Herd Base/Hou Creek wharf and camps, roads, FEED for wells, gas gathering, condensate stripping, and pipelines. To date, $32.4 million of expenditures relates to the $79.5 million commitment for the license. Expenditure on delineation wells for development of our PRL 15 resource will meet our well commitment requirements under the license.

In addition, we are required to spend $68.4 million on development of the Triceratops field in PRL 39 by the end of 2018. Minimal work on this commitment has been completed as at December 31, 2013.

We do not have sufficient funds to complete planned exploration and development in our licenses and will need to raise additional funds to complete programs and meet our exploration commitments. Therefore, we must extend or secure sufficient funding through renewed borrowings, equity raising and/or asset sales to raise cash to meet these obligations and complete these long-term plans. No assurances can be given that we will obtain new capital on terms acceptable to us, or at all. The availability and cost of financing depends on market conditions and our condition at the time we raise capital. We can provide no assurances that we will be able to obtain financing or complete sales on terms that are acceptable.

Management Discussion and Analysis   INTEROIL CORPORATION   37

Midstream - Refining

We believe we will have sufficient funds from operations to pay our estimated capital expenditures associated with our Midstream - Refining segment in 2014. We also believe cash flows from operations will be sufficient to cover refinery costs and financing charges under our crude import facility. Should there be long-term deterioration in refining margins, our refinery may not generate sufficient cash to cover all of the interest and principal payments under our secured loan agreements. As a result, we may be required to raise additional capital and/or refinance these facilities.

Downstream

On the basis of current market conditions and the status of our business, we believe that our cash flows from operations will be sufficient to meet our estimated capital expenditure for our wholesale and retail distribution business segment for 2014. Should there be a major long-term deterioration in wholesale or retail margins, our Downstream operations may not generate sufficient cash to cover all of the interest and principal payments under our loan agreements. As a result, we may be required to raise additional capital and/or refinance these facilities in the future.

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.

	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 (1)		146,211		94,219		51,992		-		-		-		-
Secured and unsecured loans		222,604		146,228		24,290		26,860		25,226		-		-
2.75% Convertible notes obligations		73,688		1,925		71,763		-		-		-		-
Indirect participation interest - PNGDV		-		-		-		-		-		-		-
Total		442,503		242,372		148,045		26,860		25,226		-		-

(1) The amount pertaining to the petroleum prospecting and retention licenses represents the amount the Company has committed on these licenses as at December 31, 2013. Further, the terms of grant of PRL 15 require us to spend a further $47.1 million on the development of the Elk and Antelope fields by the end of 2015 and the grant of PRL 39 requires us to spend a further $67.1 million on the license area by the end of 2018. Subsequent to year end, new petroleum prospecting licenses have been issued with new commitments attached to them - refer below for the details on the new license commitments.

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. When these new licenses were approved, petroleum prospecting license commitments noted above as at December 31, 2013 were terminated and replaced with the new license commitments. The new commitments require us to spend a total of $532.0 million over their six year term. The three wells, Wahoo-1, Raptor-1 and Bobcat-1, are being drilled under the new licenses, and are part of the new drilling commitments.

Off Balance Sheet Arrangements

Neither during the year ended, nor as at December 31, 2013, did we have any off balance sheet arrangements or any relationships with unconsolidated entities or financial partnerships.

Management Discussion and Analysis   INTEROIL CORPORATION   38

Transactions with Related Parties

(a) Key management compensation

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 on 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.

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, 2013, we had 49,217,242 common shares (50,602,314 common shares on a fully diluted basis) and no preferred shares issued and outstanding. The potential dilutive instruments outstanding as at December 31, 2013 included employee stock options and restricted stock in respect of 653,068 common shares and 732,004 common shares relating to the $70.0 million principal amount 2.75% convertible senior notes due November 15, 2015.

As of March 28, 2014, we had 50,022,600 common shares (51,300,618 common shares on a fully diluted basis) and no preferred shares issued and outstanding. The potential dilutive instruments outstanding as at March 28, 2013 included employee stock options and restricted stock in respect of 546,014 common shares and 732,004 common shares relating to the $70.0 million principal amount 2.75% convertible senior notes due November 15, 2015.

Derivative Instruments

Our revenues are derived from the sale of refined products. Prices for refined products and crude feedstock can be volatile and can fluctuate as a result of relatively small changes in supplies, weather, economic conditions and government actions. Due to the nature of our business, there is always a time difference between the purchase of a crude feedstock, its arrival at the refinery, and the supply of finished products to markets.

Generally, we buy crude feedstock two months in advance of it being discharged, processed and supplied or exported as finished product. Due to price fluctuations in this period, we use derivatives to reduce the risk of changes in the relative prices of our crude feedstock and refined products. These derivatives enable us to lock-in the refinery margin so we are protected from differences between our sale price of refined product and the acquisition price of our crude feedstock. Conversely, when we have locked-in the refinery margin and if the difference between our sales price of the refined products and our acquisition price of crude feedstock expands or increases, then the benefits would be limited to the locked-in margin.

The derivatives we generally use are over-the-counter swaps with credit worthy counterparties. It is common for refiners and trading companies in the Asia Pacific to use swaps to hedge their price exposures and margins, which means the swaps market is generally sufficiently liquid for hedging and risk management. Swaps cover commodities or products such as jet and kerosene, diesel, naphtha, and bench-mark crudes such as DTD Brent, Tapis and Dubai.

At December 31, 2013, we had a net payable position of $1.9 million (December 31, 2012 – net receivable of $0.2 million) relating to open contracts to sell gasoil crack swaps; buy/sell dated Brent swaps; and sell naphtha crack swaps for which hedge accounting has not been applied. The swaps that have been priced out as of December 31, 2013 will be settled in future.

Management Discussion and Analysis   INTEROIL CORPORATION   39

INDUSTRY TRENDS AND KEY EVENTS

Competitive Environment and Regulated Pricing

While we are the sole refiner of hydrocarbons in Papua New Guinea, other operators are free to establish refineries. Domestic distributors who buy their refined petroleum products from us, or from any other refinery in Papua New Guinea, are required to pay an import parity price (“IPP”) which is monitored by the ICCC. In general, the import parity price is that which would be paid in Papua New Guinea for a refined product being imported. For all price-controlled products (diesel, unleaded petrol, kerosene and aviation fuel) produced and sold in Papua New Guinea, the import parity price is calculated by adding to the Mean of Platts Singapore (“MOPS”) the costs that would typically be incurred to import such product. MOPS is the benchmark price for refined products in the region in which we operate.

In our refining business, we compete with several companies for crude oil and other feedstock and for outlets for our refined products. Many of our competitors obtain a significant portion of their feedstock from owned production, which may enable them to pay a lower cost. The high cost of transporting goods to and from Papua New Guinea reduces the availability of alternative fuel sources and retail outlets for our refined products. Competitors that have their own production or extensive distribution networks are able to offset losses from refining operations with profits from producing or retailing operations, and may be better positioned to withstand depressed refining margins or feedstock shortages. In addition, new technology is making refining more efficient, which could lead to lower prices and reduced margins. We cannot be certain that we will be able to implement new technologies in a time or at a cost acceptable to us.

We are also a significant participant in the retail and wholesale distribution business in Papua New Guinea. The ICCC regulates the maximum wholesale and retail prices and margins that may be charged in Papua New Guinea. Margins were last reviewed by the ICCC in the quarter ended December 31, 2013 and will be reviewed again in the quarter ended December 31, 2014. We and our competitors may charge less than the maximum margin set by the ICCC to be competitive.

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

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 2012. Gearing was 26% in December 2013, 19% in December 2012 and 12% in December 2011.

Management Discussion and Analysis   INTEROIL CORPORATION   40

We had cash, cash equivalents and cash restricted of $115.2 million as at December 31, 2013, of which $53.2 million was restricted. For details of other financial arrangements, see “Liquidity and Capital Resources – Summary of Debt Facilities”.

On November 11, 2013, we 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. The facility is secured by our existing Upstream and Corporate entities. The facility was initially payable in full within two months of announcing any sale or disposal of our interest in the Elk and Antelope fields. Subsequent to year end, the lenders approved a request to extend this repayment date until April 30, 2014 or the completion of any sale agreement, whichever is earlier. Post completion of the Total SPA on March 26, 2014, this facility is expected to be repaid in April 2014. As at December 31, 2013, $100.0 million of the facility had been drawn down, and the remainder was available for use according to the terms of the facility.

We also had $78.3 million of the combined BNP working capital facility available for use in our Midstream – Refining operations, and $24.7 million of the Westpac/BSP combined working capital facility available for use in our Downstream operations.

Crude Prices

Crude prices fluctuated throughout 2013, with the price of Dated Brent crude oil (as quoted by Platts) starting the year at $113 per barrel and closing the year at $110 per barrel. The average price for Dated Brent for 2013 was $109 per barrel compared with $112 per barrel for Dated Brent for 2012 and $111 per barrel for Dated Brent for 2011. Dated Brent peaked in February 2013 at $119 per barrel and was at its lowest in April 2013 at $97 per barrel.

At year end, we had $78.3 million of the combined BNP working capital facility available for use in our Midstream – Refining operations, and approximately $24.7 million of the Westpac/BSP combined working capital facility available for use in our Downstream operations. Any increase in prices will have an impact on the use of our working capital facilities, and related interest and financing charges on the used amounts.

Any volatility of crude prices means that we face significant timing and margin risk on our crude cargoes. A significant portion of this timing and margin risk is managed by us through short and long-term hedges. As at December 31, 2013, there was a net payable of $1.9 million relating to open contracts to sell gasoil crack swaps and naphtha crack swaps and buy/sell Dated Brent swaps for which hedge accounting has not been applied.

Refining Margin

The distillation process used by our refinery to convert crude feedstock into refined products is commonly referred to as hydroskimming.  While the Singapore Tapis hydroskimming margin is a useful indicator of the general margin available for hydroskimming refineries in the region in which we operate, differences in our approach to crude selection, transportation costs and import parity pricing work so that our realized margin generally differs.  

Distillate margins to Dated Brent remained consistent during 2013 compared with 2012. Naphtha crack spreads were negative but improving toward the end of 2013, which was a positive impact on our gross margin with more volume in naphtha sales and an improved premium on term contracts.

Domestic Demand

Sales results for our refinery for 2013 indicate that Papua New Guinea’s domestic demand for middle distillates (which includes diesel and jet fuels) from the refinery has stayed relatively constant since 2012.  However, the total volume of all products sold by us was 9.3 MMbbls for 2013 compared with 8.5 MMbbls in 2012 and 7.2 MMbbls in 2011.  The increase in the total volume of products sold mainly relates to the change in the crude diet of our refinery during the current year ended December 31, 2013 with lower distillate yielding crudes being used to maximize throughput. Any increased naphtha and low-sulphur waxy residue volumes are exported by our refinery. Total volume of PNG domestic sales for 2013 was 5.2 million barrels compared with 5.3 million barrels in 2012 and 4.6 million barrels in 2011.

Management Discussion and Analysis   INTEROIL CORPORATION   41

The refinery on average sold 14,246 bblspd of refined petroleum products to the domestic market during 2013 compared with 14,520 bblspd in 2012 and 12,649 bblspd in 2011. 

Interest Rates

The LIBOR USD overnight rate is the benchmark floating rate used in our midstream working capital facility and therefore accounts for a significant proportion of our interest rate exposure. The LIBOR USD overnight rate remained constant between 0.10% and 0.20% for most of 2013. Any rate increases would add additional cost to financing our crude cargoes and vice versa as our BNP Paribas working capital facility is linked to LIBOR rates.

Exchange Rates

Changes in the PGK to USD exchange rate affect our refinery results because of the timing difference between foreign exchange rates used when setting the monthly IPP price in PGK, and the foreign exchange rate used to convert the subsequent receipt of PGK proceeds to USD to repay our crude cargo borrowings. The PGK interbank reference rate has weakened considerably against the USD in the financial year ended December 31, 2013 (from 0.4755 to 0.4130). However, the underlying market rates in the same period have fallen further and are currently 300-400 basis points below the interbank rate, which has resulted in significant realized and unrealized foreign exchange losses during the year

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. 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, we are 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 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 2013 Annual Information Form 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 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. The information about our critical accounting estimates should be read in conjunction with Note 2 of the notes to our consolidated financial statements for the year ended December 31, 2013, available at www.sedar.com which summarizes our significant accounting policies.

Income Taxes

We use the asset and liability method of accounting for income taxes. Under this method, deferred tax assets and liabilities are recognized for the deferred tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the date of enactment. In considering the recoverability of deferred tax assets and liabilities, we consider several factors, including the consistency of profits generated from the refinery, likelihood of production from Upstream operations to use the carried forward exploration costs, etc. If actual results differ from the estimates or we adjust the estimates in future periods, a reduction in our deferred tax assets will result in a corresponding increase in deferred tax expenses.

Management Discussion and Analysis   INTEROIL CORPORATION   42

As at December 31, 2013, we have a total of approximately $400.7 million in temporary differences and carried forward losses for exploration expenditure in Papua New Guinea (including Total’s share of exploration expenditure, with the tax benefit to be transferred to Total on completion of the SPA). No deferred tax assets have been recognized for this exploration expenditure as at December 31, 2013. The initial tax benefit to be recognized would be 30% of the temporary differences and losses carried forward through the income statement. We will consider recognition of the deferred tax assets when we have more certainty around the timing of assessable income in the Upstream segment. The ultimate realization of deferred tax assets depends on the generation of future taxable income during the periods in which those temporary differences become deductible. We consider 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.

Oil and Gas Properties

We use the successful-efforts method to account for our oil and gas exploration and development. 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.

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 on current regulations and economic circumstances at period end. In January 2013, we 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. These costs have been capitalized as part of the cost of the refinery and are depreciated over the life of the asset. The provision will be accreted over the remaining useful life of the refinery to bring the provision to the estimated expenditure required at the time of decommissioning. The asset retirement obligation as at December 31, 2013 was $4,948,017. If we adjust the estimates in future periods, it may result in increased capital expenditure and a corresponding increase in liabilities.

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 prospectively. We currently do not have any amounts accrued for environmental remediation obligations because 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   43

Impairment of Long-Lived Assets

We are required to review the carrying value of all property, plant and equipment, including the carrying value of oil and gas 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.

Net realizable value of inventory

Inventory is recorded at the lower of cost or net realizable value. To determine the net realizable value of finished goods inventory, the IPP pricing from January 2014 is considered (IPP is based on December MOPS product pricing) along with estimated Naphtha, LSWR and LPG pricing based on the expected date of sale. The estimates are based on the most reliable evidence available at the time the estimates are made, of the amounts that are expected to be realized. These estimates consider fluctuations of price or cost directly relating to events occurring after the end of the period to the extent that such events confirm conditions existing at the end of the reporting period.

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.

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, terms of the option, vesting criteria, share price at grant date, expected price volatility of the underlying share, 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.

Legal and Other Contingent Matters

We are required to determine whether a loss is probable based on judgment and interpretation of laws and regulations and whether the loss can reasonably be estimated. When the amount of a contingent loss is determined it is charged to earnings. We continually monitor known and potential contingent matters and make appropriate provisions by charges to earnings when warranted.

NEW ACCOUNTING STANDARDS

New accounting standards not yet applicable as at December 31, 2013

These new standards have been issued but are not yet effective for the financial year beginning January 1, 2013 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   44

NON-GAAP MEASURES AND RECONCILIATION

Non-GAAP measures, including gross margin and 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. Gross margin is a non-GAAP measure and is “sales and operating revenues” less “cost of sales and operating expenses”. This table reconciles sales and operating revenues, a GAAP measure, to gross margin.

Consolidated – Operating results	Year ended December 31,
($ thousands)	2013			2012			2011
Midstream – Refining		1,197,762			1,095,925			939,278
Downstream		834,309			862,958			743,860
Corporate		26,593			22,846			14,125
Consolidation Entries		(662,965	)		(673,677	)		(590,729	)
Sales and operating revenues		1,395,699			1,308,052			1,106,534
Midstream – Refining		(1,127,323	)		(1,071,852	)		(897,825	)
Downstream		(771,116	)		(800,217	)		(704,213	)
Corporate (1)		(22,056	)		(18,905	)		(11,421	)
Consolidation Entries		660,982			671,786			592,527
Cost of sales and operating expenses		(1,259,513	)		(1,219,188	)		(1,020,932	)
Midstream – Refining		70,439			24,073			41,453
Downstream		63,193			62,741			39,647
Corporate (1)		4,537			3,941			2,704
Consolidation Entries		(1,983	)		(1,891	)		1,798
Gross Margin		136,186			88,864			85,602

(1) Corporate expenses are classified below the gross margin line and mainly relates to ‘Office and admin and other expenses’ and ‘Interest expense’.

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 income/(loss), a GAAP measure, to EBITDA, a non-GAAP measure for each of the last eight quarters.

Management Discussion and Analysis   INTEROIL CORPORATION   45

Quarters ended	2013												2012
($ thousands)	Dec-31			Sep-30			Jun-30			Mar-31			Dec-31			Sep-30			Jun-30			Mar-31
Upstream		(19,974	)		(2,842	)		(19,478	)		(1,311	)		(873	)		956			(5,730	)		(6,374	)
Midstream – Refining		10,246			(3,562	)		840			12,701			12,370			13,417			(42,647	)		18,933
Midstream – Liquefaction		87			2,550			19,850			(123	)		192			11			672			(1,410	)
Downstream		14,366			14,962			7,542			10,062			12,258			9,275			11,102			21,414
Corporate		6,055			13,446			1,745			10,044			14,133			9,841			9,975			9,188
Consolidation Entries		(16,082	)		(14,647	)		(11,146	)		(13,418	)		(12,199	)		(14,503	)		(9,871	)		(14,216	)
Earnings before interest, taxes, depreciation and amortization		(5,302	)		9,907			(647	)		17,955			25,881			18,997			(36,499	)		27,535
Subtract:
Upstream		(13,056	)		(12,814	)		(12,043	)		(11,941	)		(11,734	)		(11,438	)		(10,517	)		(9,408	)
Midstream – Refining		(2,417	)		(2,351	)		(2,235	)		(2,454	)		(11,390	)		(1,654	)		(2,011	)		(2,771	)
Midstream – Liquefaction		(517	)		(177	)		(566	)		(558	)		(586	)		(584	)		(579	)		(559	)
Downstream		(531	)		(536	)		(263	)		(422	)		(337	)		(394	)		(909	)		(1,233	)
Corporate		(1,408	)		(1,842	)		(2,081	)		(1,600	)		(1,601	)		(1,540	)		(1,535	)		(1,510	)
Consolidation Entries		13,103			12,989			12,677			12,642			12,552			12,482			12,044			12,047
Interest expense		(4,826	)		(4,731	)		(4,511	)		(4,333	)		(13,096	)		(3,128	)		(3,507	)		(3,434	)
Upstream		-			-			-			-			-			-			-			-
Midstream – Refining		(4,476	)		(1,736	)		(118	)		(1,270	)		16,574			(3,484	)		14,580			(1,948	)
Midstream – Liquefaction		-			-			-			-			-			-			-			-
Downstream		(3,411	)		(3,804	)		(1,667	)		(2,455	)		(3,070	)		(1,791	)		(2,907	)		(5,746	)
Corporate		(950	)		108			(483	)		(196	)		(1,330	)		177			535			(880	)
Consolidation Entries		-			-			-			-			-			-			-			-
Income taxes		(8,837	)		(5,432	)		(2,268	)		(3,921	)		12,174			(5,098	)		12,208			(8,574	)
Upstream		(505	)		(550	)		(525	)		(522	)		(474	)		(454	)		715			(1,462	)
Midstream – Refining		(3,279	)		(3,425	)		(3,162	)		(3,122	)		(4,153	)		(2,921	)		(2,891	)		(2,894	)
Midstream – Liquefaction		-			-			-			-			-			-			-			-
Downstream		(1,187	)		(1,187	)		(1,266	)		(1,180	)		(1,135	)		(1,464	)		(1,241	)		(1,240	)
Corporate		(910	)		(932	)		(882	)		(906	)		(683	)		(629	)		(530	)		(528	)
Consolidation Entries		33			32			31			32			31			33			32			33
Depreciation and amortisation		(5,848	)		(6,062	)		(5,804	)		(5,698	)		(6,414	)		(5,435	)		(3,915	)		(6,091	)
Upstream		(33,535	)		(16,206	)		(32,046	)		(13,774	)		(13,081	)		(10,936	)		(15,532	)		(17,244	)
Midstream – Refining		74			(11,074	)		(4,675	)		5,855			13,401			5,358			(32,969	)		11,320
Midstream – Liquefaction		(430	)		2,373			19,284			(681	)		(394	)		(573	)		93			(1,969	)
Downstream		9,237			9,435			4,346			6,005			7,716			5,626			6,045			13,195
Corporate		2,787			10,780			(1,701	)		7,342			10,519			7,849			8,445			6,270
Consolidation Entries		(2,946	)		(1,626	)		1,562			(744	)		384			(1,988	)		2,205			(2,136	)
Net (loss)/profit per segment		(24,813	)		(6,318	)		(13,230	)		4,003			18,545			5,336			(31,713	)		9,436

PUBLIC SECURITIES FILINGS

You may access additional information about us, including our 2013 Annual Information Form, 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. Securities and Exchange Commission at www.sec.gov. Additional information is also available on our website www.interoil.com.

Management Discussion and Analysis   INTEROIL CORPORATION   46

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, 2013 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, 2013, for the foregoing purpose.

No material change in our internal controls over financial reporting were identified during the year ended December 31, 2013, that have materially affected, or are reasonably likely to materially affect, our internal controls 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   47