EX-99.1 2 v359888_ex99-1.htm EXHIBIT 99.1

InterOil Corporation

Management

Discussion and Analysis

For the quarter and nine months ended September 30, 2013

November 11, 2013

TABLE OF CONTENTS

FORWARD-LOOKING STATEMENTS	2
OIL AND GAS DISCLOSURES	3
INTRODUCTION	4
BUSINESS STRATEGY	4
OPERATIONAL HIGHLIGHTS	5
SELECTED FINANCIAL INFORMATION AND HIGHLIGHTS	7
QUARTER AND NINE MONTH PERIOD IN REVIEW	14
LIQUIDITY AND CAPITAL RESOURCES	23
RISK FACTORS	33
CRITICAL ACCOUNTING ESTIMATES	33
NEW ACCOUNTING STANDARDS	34
NON-GAAP MEASURES AND RECONCILIATION	34
PUBLIC SECURITIES FILINGS	36
DISCLOSURE CONTROLS AND PROCEDURES AND INTERNAL CONTROLS OVER FINANCIAL REPORTING	36
GLOSSARY OF TERMS	37

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, 2012, our annual information form (the “2012 Annual Information Form”) for the year ended December 31, 2012 and our unaudited condensed consolidated interim financial statements and accompanying notes for the quarter and nine months ended September 30, 2013. This MD&A was prepared by management and provides a review of our performance in the quarter and nine months ended September 30, 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,” and “InterOil” refer to InterOil Corporation or InterOil Corporation and its subsidiaries as the context requires. Information presented in this MD&A is as at September 30, 2013 and for the quarter and nine months ended September 30, 2013 unless otherwise specified. A listing of specific defined terms can be found in the “Glossary of Terms” section found at the end of this MD&A.

Management Discussion and Analysis INTEROIL CORPORATION 1

FORWARD-LOOKING STATEMENTS

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

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; entering into definitive agreements with joint venture partners; entering into a definitive agreement for the development of our PRL15 resource; the construction and development of the LNG Project and the Condensate Stripping Project in Papua New Guinea; the timing and cost of such construction and development; the 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; the timing, maturity and amount of future capital and other expenditures.

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

our ability to negotiate a definitive agreement for the development of our PRL15 resource;

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 time periods and upon reasonable terms;

the inherent uncertainty of oil and gas exploration activities;

the availability of crude feedstock at economic rates;

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

difficulties with the recruitment and retention of qualified personnel;

losses from our hedging activities;

fluctuations in currency exchange rates;

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;

the 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 default;.

interest rate risk;

weather conditions and unforeseen operating hazards;

general economic conditions, including any further economic downturn, the availability of credit, the European sovereign debt credit crisis and the 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.

Management Discussion and Analysis INTEROIL CORPORATION 2

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 carry out development activities, the ability to market products successfully to current and new customers, the effects from increasing competition, the ability to obtain financing on acceptable terms, and the ability to develop reserves and production through development and exploration activities. Although we consider these assumptions to be reasonable based on information currently available to us, they may prove to be incorrect.

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 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 2012 Annual Information Form.

Furthermore, the 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.

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, 2012 in accordance with NI 51-101, which evaluation is summarized in our 2012 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 September 30, 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.

Management Discussion and Analysis INTEROIL CORPORATION 3

INTRODUCTION

We are developing a fully integrated energy company operating in Papua New Guinea and the surrounding Southwest Pacific region. Our operations are organized into four major segments:

Segments		Operations

Upstream		Exploration and Production – Explores, appraises and develops crude oil and natural gas structures in Papua New Guinea within PPL236, PPL237, PPL238, PRL15 and APRL39.

Midstream		Refining – Produces refined petroleum products at Napa Napa in Port Moresby, Papua New Guinea for the domestic market and for export. Liquefaction – Developing in joint venture and as non-operator liquefaction and associated facilities in Papua New Guinea for the export of LNG.

Downstream		Wholesale and Retail Distribution – Markets and distributes refined products domestically in Papua New Guinea on a wholesale and retail basis.

Corporate		Corporate – Provides support to our other business segments by engaging in business development and improvement activities and providing general and administrative services and management, undertakes financing and treasury activities, and is responsible for government and investor relations. This segment also manages our shipping business which currently operates two vessels that transport petroleum products for our Downstream segment and external customers, both within Papua New Guinea and for export in the South Pacific region. Our Corporate segment results also include consolidation adjustments.

BUSINESS STRATEGY

Our strategy is to develop a vertically integrated energy company in Papua New Guinea and the surrounding region, focusing on niche market opportunities which provide financial rewards for our shareholders, while being environmentally responsible, providing a quality working environment and contributing positively to the communities in which we operate. A significant element of that strategy is to develop in joint venture and as non-operator of gas liquefaction and condensate stripping facilities in Papua New Guinea and to establish gas and gas condensate reserves.

We plan to achieve this strategy by:

Developing our position as a prudent and responsible business operator;

Enhancing our existing refining and distribution businesses;

Monetizing our discovered resources;

Maximizing the value of our exploration assets; and

Positioning for long term success.

Further details of our business strategy can be found under the heading “Business Strategy” in our 2012 Annual Information Form available at www.sedar.com.

Management Discussion and Analysis INTEROIL CORPORATION 4

OPERATIONAL HIGHLIGHTS

Summary of operational highlights

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

Upstream

On July 16, 2013, we entered into a Settlement and Termination Deed with Mitsui following the termination of the CSP JVOA on February 28, 2013. In accordance with the deed, we repaid Mitsui $34.4 million in relation to the cancellation of option to acquire interests in the Elk and Antelope fields, and Mitsui’s share of capital expenditure incurred on the condensate stripping facilities, the unsecured loan, together with interest thereon. The facility has now been fully repaid and all security provided to Mitsui discharged.

The work program undertaken on behalf of OSE in the combined seismic over their PPL338 and our PPL237 licenses was completed. OSE has requested additional lines be acquired on their behalf in the coming quarter. We will continue to act as the operator of the work program under a data sharing and joint processing arrangement. During the quarter, previous seismic data obtained from DPE archives over the Raptor prospect in PPL237 was reprocessed. With advances in technology the reprocessed data will provide a better understanding of the prospectively of the acreage and identify well locations.

Subsequent to quarter end, a multi-well drilling and seismic work program and budget was approved by our Board. The work program consists of six wells (1 well each in our prospecting licenses PPL236, 237 and 238, 2 appraisal wells in PRL15, and 1 well in APRL39), plus a seismic program in Triceratops east, southwest Antelope and a new prospect Bobcat located on PPL238.

Subsequent to quarter end, on October 24, 2013, we entered into an Exchange Agreement with PNGEI to buyback their 4.25% indirect participation interest percentage under the Amended Indirect Participation Interest Agreement dated May 12, 2004, including their interest and rights to future distributions in exchange for 100,000 of our common shares.

Subsequent to quarter end, on November 11, 2013, we entered into a $250.0 million secured syndicated capital expenditure facility led by Credit Suisse AG related to the approved seismic data acquisition and drilling program. In addition to Credit Suisse, the participating lenders are Commonwealth Bank of Australia (“CBA”), Australia and New Zealand Banking Group Limited (“ANZ”), UBS AG, Macquarie Group Limited (“Macquarie”), Bank South Pacific Limited (“BSP”), BNP Paribas and Westpac Bank PNG Limited (“Westpac”). The facility is secured by our existing Upstream and Corporate entities. The 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% every two months to a maximum of 11.5% in the last two months of the 12-month term. The facility is payable in full (within a certain timeframe) upon any sale or disposal of our interest in the Elk and Antelope fields.

Our exclusivity agreement with ExxonMobil Papua New Guinea, a subsidiary of ExxonMobil, in connection with negotiations for the development of our PRL15 resource expired on July 25, 2013. Although negotiations regarding the development of this resource are ongoing, we can give no assurances that we will be successful in completing a transaction on terms acceptable to us or at all.

Midstream –Liquefaction

On August 6, 2013, we signed an agreement with PacLNG relating to the alignment of interests in the Midstream – Liquefaction Joint Venture to those in the PRL15. Following the alignment, our interest in the joint venture is 77.165% and PacLNG’s interest is 22.835%.

Midstream – Refining

Total refinery throughput for the quarter ended September 30, 2013 was 26,786 barrels per operating day, compared with 23,980 barrels per operating day during the quarter ended September 30, 2012.

Capacity utilization of the refinery for the quarter ended September 30, 2013, based on 36,500 barrels per day operating capacity, was 65% compared with 61% for quarter ended September 30, 2012. During the quarters ended September 30, 2013 and 2012, our refinery was shut down for 11 days and 9 days, respectively, for general maintenance activities.

Management Discussion and Analysis INTEROIL CORPORATION 5

On July 17, 2013, we entered into a $350.0 million working capital structured facility arranged by BNP Paribas to replace the existing $240.0 million facility. Out of the $350.0 million, $270.0 million is a syndicated secured working capital facility with the support of five banking partners, namely BNP Paribas, Australia and New Zealand Banking Group Limited, Natixis, Intesa Sanpaolo, and Bank South Pacific Limited, which includes the ability 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. The credit portion of the facility bears interest at LIBOR plus 3.75% per annum.

The PGK weakened against USD during the quarter ended September 30, 2013 from 0.4570 to 0.4160, compared to the same period in 2012 when it weakened slightly from 0.4840 to 0.4805. This weakening of the PGK, and lack of liquidity of the currency, has had an unfavorable impact on the refinery results during the quarter ended September 30, 2013. The PGK exchange rate does form 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

Volumes sold during the quarter ended September 2013 increased over the previous quarter and the same quarter of last year as a result of increased sales of Diesel and Jet A1. This increase in volumes were partly due to plant problems at the third party owned Hides based refinery, and the resultant increased purchasing of product from our terminals while that plant was being repaired. In addition, Jet A1 volumes were boosted over this period by the ExxonMobil led PNGLNG project and the movement of the conditioning plant by heavy cargo aircraft from Port Moresby to Komo, and the Australian Government contracts for moving plant and equipment to Manus Island for Asylum Seeker accommodation. Total sales volumes for the third quarter ended September 30, 2013 were 194.7 million liters (September 2012 – 185.0 million liters), an increase of 9.7 million liters, or 5.2% over the same period in 2012.

Our retail business accounted for approximately 14% of our total downstream sales in the quarter ended September 2013 (September 2012 – 15%). During the quarter, we acquired a high volume independently owned retail site.

On August 19, 2013, we entered into a one year $75.0 million equivalent combined secured loan facility with Westpac and BSP to be drawn in tranches, either USD and/or PGK. Borrowings under the facility will be used for exploration and drilling activities with $37.5 million available immediately, and a further $37.5 million to be available upon the execution of an agreement in relation to the monetization of the Elk and Antelope resource. The principal repayment will be made on the earlier of, the first resource payment or 12 months from the first drawdown. This facility is secured against our Downstream assets and undertakings. Subsequent to the quarter end, after the Credit Suisse facility closed, the second tranche of $37.5 million was cancelled.

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 nine months ended September 30, 2013 of $3.7 million.

On July 11, 2013, Dr. Michael Hession was appointed as our Chief Executive Officer. Dr. Hession has over 25 years of international exploration, operation and commercial experience, most recently as a Senior Vice President at Browse LNG Development, a division of Woodside Energy Ltd (WPLAX).

Management Discussion and Analysis INTEROIL CORPORATION 6

SELECTED FINANCIAL INFORMATION AND HIGHLIGHTS

Consolidated Results for the Quarters Ended and Nine Months Ended September 30, 2013 and 2012

Consolidated – Operating results	Quarter ended September 30,						Nine months ended September 30,
($ thousands, except per share data)	2013			2012			2013			2012
				(revised) ⁽⁴⁾						(revised) ⁽⁴⁾
Sales and operating revenues		304,410			324,109			997,809			956,336
Interest revenue		20			23			71			226
Other non-allocated revenue		805			2,731			3,346			7,557
Total revenue		305,235			326,863			1,001,226			964,119
Cost of sales and operating expenses		(274,183	)		(286,330	)		(909,241	)		(902,958	)
Office and administration and other expenses		(10,981	)		(13,570	)		(38,949	)		(37,952	)
Derivative losses		(2,452	)		(4,929	)		(3,274	)		(4,715	)
Exploration costs		(2,992	)		(2,056	)		(3,964	)		(14,660	)
Gain on conveyance of oil and gas properties		-			2,895			500			2,895
Gain on Flex LNG investment		4,747			-			3,720			-
Foreign exchange (losses)/gains		(12,045	)		(3,494	)		(25,069	)		3,993
Share of net profit/(loss) of joint venture partnership accounted for using the equity method ⁽⁴⁾		2,578			(382	)		2,265			(688	)
EBITDA ⁽¹⁾		9,907			18,997			27,214			10,034
Depreciation and amortization		(6,062	)		(5,435	)		(17,563	)		(15,442	)
Interest expense		(4,731	)		(3,128	)		(13,575	)		(10,070	)
(Loss)/profit before income taxes		(886	)		10,434			(3,924	)		(15,478	)
Income tax expense		(5,432	)		(5,098	)		(11,621	)		(1,463	)
Net (loss)/profit		(6,318	)		5,336			(15,545	)		(16,941	)
Net (loss)/profit per share (basic)		(0.13	)		0.11			(0.32	)		(0.35	)
Net (loss)/profit per share (diluted)		(0.13	)		0.11			(0.32	)		(0.35	)
Total assets		1,263,110			1,202,935			1,263,110			1,202,935
Total liabilities		512,705			445,234			512,705			445,234
Total long-term liabilities		249,058			139,654			249,058			139,654
Gross margin ⁽²⁾		30,227			37,779			88,568			53,378
Cash flows generated from/(used in) operating activities ⁽³⁾		26,140			24,902			9,500			(27,860	)

Notes:

(1)

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

(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 Condensed Consolidated Interim 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 PNG LNG joint venture, which were included in the EBITDA calculation.

Management Discussion and Analysis INTEROIL CORPORATION 7

Analysis of Financial Condition Comparing Quarters and Nine Months Ended September 30, 2013 and 2012

During the nine months ended September 30, 2013, our debt-to-capital ratio (being debt divided by [shareholders’ equity plus debt]) was 20% (13% as at September 30, 2012), well below our targeted maximum gearing level of 50%. Gearing targets are based on a number of factors including operating cash flows, future cash needs for development, capital market conditions 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 1.3 times as at September 30, 2013 (1.4 times as at September 30, 2012). 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 September 30, 2013 (0.8 times as at September 30, 2012). The current ratio and quick ratio were below our internal targets of above 1.5 and 1.0 times respectively as at September 30, 2013. The execution of the agreements related to the development of PRL 15 resource is expected to bring these ratios within our internal targets.

As at September 30, 2013, our total assets amounted to $1,263.1 million, compared with $1,202.9 million as at September 30, 2012. This increase of $60.2 million, or 5%, from September 30, 2012 was primarily due to:

$97.7 million expenditure on our oil and gas properties associated with the appraisal and development of the Elk and Antelope fields including the drilling of the Antelope-3 well, preparation and drilling of the Triceratops-2 well, preparatory work on the Elk-3 well, and Herd Base and Hou Creek infrastructure construction;

$29.7 million increase in non-current receivables was attributable to the 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;

$17.5 million increase in equity accounted investment in PNG LNG joint venture due to agreement with PacLNG relating to the alignment of interests in the Midstream – Liquefaction Joint Venture to those in the PRL15;

$13.7 million increase in inventories balances due to the timing of shipments; and

$6.1 million increase in deferred tax assets mainly relates to the refinery’s increased carried forward tax losses.

These increases however have been partially offset by:

$80.2 million decrease in our trade and other receivables due to change in our discounting facility to a non-recourse basis; and

$17.4 million net reduction in cash and cash equivalents and restricted cash, primarily resulting from the termination settlement made to Mitsui and expenditure on the development of oil and gas properties, partly offset by the receipt of PRE’s $76.0 million initial staged cash payment during the nine month period.

As at September 30, 2013, our total liabilities amounted to $512.7 million, compared with $445.2 million at September 30, 2012. The increase of $67.5 million, or 15%, from September 30, 2012 was primarily due to:

total receipts of PRE’s $76.0 million initial staged cash payment (part of the $116.0 million initial stage cash payment) held as a liability due to their option to exit the farm-in agreement;

net increase of $67.8 million in secured loans payable on drawdown of the ANZ, BSP and BNP syndicated secured loan facility of $95.9 million (net of transaction costs) and drawdown of the BSP & Westpac combined secured loan facility of $34.6 million, partially reduced by the OPIC loan repayment of $35.5 million during the last quarter of 2012; and

$5.6 million increase in income tax payable due to income tax on profits generated by the Downstream segment.

These increases however have been offset by a $95.5 million decrease in accounts payable and accrued liabilities, mainly related to timing of payments on certain crude cargo purchases and change in our discounting facility to a non-recourse basis.

Management Discussion and Analysis INTEROIL CORPORATION 8

Analysis of Consolidated Financial Results Comparing Quarters and Nine Months Ended September 30, 2013 and 2012

Quarterly Comparative

Our net loss for the quarter ended September 30, 2013 was $6.3 million compared with a net profit of $5.3 million for the same quarter of 2012, a decrease of profit by $11.6 million. The operating segments of Corporate, Midstream - Refining and Downstream collectively derived a net profit for the quarter of $7.5 million (2012 net profit $16.8 million), while the investments in development segments of Upstream and Midstream - Liquefaction resulted in a net loss of $13.8 million (2012 net loss $11.5 million).

The decrease in net profit for the quarter ended September 30, 2013 was mainly due to:

$8.6 million increase in foreign exchange losses, resulting from the weakening of PGK against USD during the quarter ended September 30, 2013 (FX rate decreased from 0.4570 to 0.4160) compared to the same period in 2012 (decreased from 0.4840 to 0.4805);

$7.6 million decrease in gross margin on account of a relatively stable crude and product prices movement during the current quarter ended September 30, 2013 as compared to increases in the same quarter of 2012;

$2.9 million decrease in gain on conveyance of oil and gas properties due to the recognition of sale of interest in PPL 237 to PRE during third quarter of 2012; and

$1.9 million decrease in non-allocated revenue for the reduced utilization of construction and related equipment on civil works and related infrastructure development associated with the PRL 15 development works.

These decreases in net profit however have been partly offset by a $4.7 million gain on disposal of FLEX LNG shares; and a $3.0 million increase in share of net profit of joint venture partnership on equalization of PacLNG’s interest in PNG LNG Inc. Joint Venture to their interest in PRL15.

Total revenues decreased by $21.6 million from $326.8 million in the quarter ended September 30, 2012 to $305.2 million in the quarter ended September 30, 2013, primarily due to lower sales volumes during the quarter. The total volume of all products sold by us was 2.0 million barrels for the quarter ended September 30, 2013, compared with 2.3 million barrels in the same quarter of 2012, mainly due to the timing of refinery exports in the third quarter of 2012.

Nine Monthly Comparative

Our net loss for the nine months ended September 30, 2013 was $15.5 million compared with $16.9 million for the same period of 2012, a decrease of $1.4 million. The operating segments of Corporate, Midstream - Refining and Downstream collectively derived a net profit for the nine month period of $25.5 million (2012 net profit $29.2 million), while the investments in development segments of Upstream and Midstream - Liquefaction resulted in a net loss of $41.0 million (2012 net loss $46.1 million).

During the nine month period ended September 30, 2013, there was:

$35.2 million increase in gross margin on account of relatively stable crude and product prices during the nine months ended September 30, 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, and higher premium and better crack spread from Naphtha sales during current period.

$10.7 million decrease in exploration costs incurred for seismic activity for PPL 236.

These decreases in net loss have been partly offset by:

$29.1 million increase in foreign exchange losses, resulting from the weakening of PGK against USD during the nine months ended September 30, 2013 (FX rate decreased from 0.4755 to 0.4160) compared to the same period in 2012 (increased from 0.4665 to 0.4805);

$10.2 million increase in income tax expenses primarily due to the utilization of carried forward tax losses and the impact of unfavorable foreign exchange movements impacting temporary differences on translation of the nonmonetary assets using period-end rates;

$4.2 million decrease in non-allocated revenues resulting from lower activities and related recoveries relating to the Upstream segment’s construction and drilling related activities during the current period; and

Management Discussion and Analysis INTEROIL CORPORATION 9

$2.4 million decrease in gain on conveyance of oil and gas properties, due to the recognition of sale of interest in PPL 237 to PRE during quarter ended September 2012.

Total revenues increased by $37.1 million from $964.1 million in the nine months ended September 30, 2012 to $1,001.2 million in the nine months ended September 30, 2013, primarily due to higher sales volumes during the period. The total volume of all products sold by us was 6.7 million barrels for the nine months ended September 30, 2013, compared with 6.2 million barrels in the same period in 2012.

Variance Analysis

A complete discussion of each of our business segments’ results can be found under the section “Quarter and Nine Month Period in Review”. The following analysis outlines the key variances, the net of which are the primary explanations for the changes in the consolidated results between the quarters and nine months ended September 30, 2013 and 2012.

	*Quarterly* *Variance* *($ millions)*	*Nine Month* *Variance* *($ millions)*

	*($11.7)*	*$1.4*	*Net (loss)/profit variance for the comparative periods primarily due to:*

Ø	($7.6)	$35.2	Decrease in gross margin for the quarter was mainly due to the following contributing factors: + A relatively stable crude and product prices movement during the quarter ended September 30, 2013 as compared to increasing prices in the quarter ended September 30, 2012. The average costs for Brent has increased by $9.0 per barrel in the third quarter of 2013 as compared to the $18.0 per barrel in the third quarter of 2012. Increase in gross margin for the nine month period was mainly due to the following contributing factors: + A relatively stable crude and product prices movement during the current nine months ended September 30, 2013 as compared to a large fall in prices during the second quarter of 2012 + A $24.6 million net realizable value write down made during second quarter of 2012 while there was no inventory write down required during the current period + higher Naphtha sales with overall better crack spreads and premiums

Ø	($1.9)	($4.2)	Decrease in other non-allocated revenue due to reduced utilization of construction and related equipment on civil works and related infrastructure development associated with the PRL 15.

Ø	$2.6	($1.0)	Decrease in office and administration and other expenses for the quarter were primarily attributable to a reduction in construction and project activities and related personnel in our Upstream segment compared to the same quarter of 2012. Increase in office and administration and other expenses for the nine month period was primarily attributable to higher retirement expenses incurred for the senior management offset by lower expenses as a result of a reduction in activities and personnel in our Upstream segment compared to the same period of 2012.

Management Discussion and Analysis INTEROIL CORPORATION 10

Ø	$2.5	$1.4	Decrease in derivative losses was mainly due to the lower losses incurred for the settlement of commodity contracts.

Ø	($0.9)	$10.7	Lower exploration costs incurred for seismic activity for PPL 236 during the current nine month period. The seismic costs in 2012 were in relation to the Kwalaha and Tuna seismic acquisition programs.

Ø	($2.9)	($2.4)	Decrease in gain on conveyance of oil and gas properties was mainly due to the recognition of sale of interest in PPL 237 to PRE during quarter ended September 30, 2012.

Ø	$4.7	$3.7	Increase in gain on available-for-sale investment was due to the gain recognized on the disposal of FLEX LNG shares during the quarter ended September 30, 2013.

Ø	($8.6)	($29.1)	Increase in foreign exchange losses for the quarter ended September 30, 2013 was mainly due to the weakening of PGK against USD during the quarter ended September 30, 2013 (FX rate decreased from 0.4570 to 0.4160) compared to the same period in 2012 (decreased from 0.4840 to 0.4805). Increase in foreign exchange losses for the nine months ended September 30, 2013 was mainly due to the weakening of PGK against USD during the nine months ended September 30, 2013 (FX rate decreased from 0.4755 to 0.4160) compared to the same period in 2012 (increased from 0.4665 to 0.4805).

Ø	$3.0	$3.0	Increase in share of net profit of joint venture partnership accounted using the equity method was mainly due to the $2.6 million profit recognized on the gain on disposal of our interest in PNG LNG as a result of the agreement to equalize PacLNG’s interest in PNG LNG Inc. joint venture to their interest in PRL15.

Ø	($0.6)	($2.1)	Increase in depreciation expense for the nine month period was primarily due to depreciation charge for new projects capitalized within Midstream Refining and Corporate segments.

Ø	($1.6)	($3.5)	Increase in interest expense was mainly due to the higher interest expense incurred for the drawdown of $100.0 million under the ANZ, BSP and BNP syndicated loan, interest on the drawdown of the combined Westpac and BSP secured loan facility and increased utilization of refinery working capital facilities.

Ø	($0.3)	($10.2)	Increase in income tax expenses mainly relates to the utilization of carried forward tax losses, lower current period unabsorbed business losses and the impact of unfavorable foreign exchange movements impacting temporary differences on translation of the nonmonetary assets of the refinery operation using period end rates.

Analysis of Consolidated Cash Flows Comparing Quarters and Nine Months Ended September 30, 2013 and 2012

As at September 30, 2013, we had cash, cash equivalents, and restricted cash of $79.3 million (September 30, 2012 – $96.7 million), of which $38.9 million (September 30, 2012 - $39.6 million) was restricted. Of the total restricted cash of $38.9 million, $27.3 million (September 30, 2012 - $33.6 million) was restricted pursuant to the BNP working capital facility utilization requirements, $11.2 million (September 30, 2012 – $5.6 million) was restricted as a cash deposit on the secured loans (ANZ, BSP and BNP syndicated secured loan facility as at September 30, 2013, and OPIC facility as at September 30, 2012), and the balance was made up of a cash deposit on office premises together with term deposits on our PPLs.

Management Discussion and Analysis INTEROIL CORPORATION 11

Cash flows generated from operations

Our cash inflows generated from operations for the quarter ended September 30, 2013 were $26.1 million compared with $24.9 million for the quarter ended September 30, 2012, a net increase in cash inflows of $1.2 million. This increase in cash inflows was mainly due to an $8.6 million increase in net cash inflows from operations prior to changes in operating working capital, related to the increase in net loss generated by the operations less any non-cash expenses and partly offset by a $7.4 million net decrease in working capital inflows associated with trade and other receivables, inventories and accounts payables for the quarter ended September 30, 2013.

Our cash inflows generated from operations for the nine months ended September 30, 2013 were $9.5 million compared with the cash outflows of $27.9 million for the nine months ended September 30, 2012, a net increase in cash inflows of $37.4 million. This increase in cash inflows was mainly due to a $17.5 million net decrease in working capital outflows associated with trade and other receivables, inventories and accounts payables and a $19.8 million increase in net cash inflow from operations prior to changes in operating working capital, related to the lower net loss generated by the operations less any non-cash expenses for the nine months ended September 30, 2013.

Cash flows used in investing activities

Cash outflows for investing activities for the quarter ended September 30, 2013 were $25.6 million compared with $38.6 million for the quarter ended September 30, 2012. These outflows mainly relate to the net cash expenditures on exploration, appraisal and development activities (net of IPI cash calls) of $26.3 million, expenditures on plant and equipment of $8.4 million, and a $6.2 million increase in restricted cash held as security under the BNP working capital facility. These outflows were partially offset by $7.8 million proceeds from disposal of FLEX LNG shares (net of transaction costs) and a $7.6 million increase in working capital requirements of development segments relating to the timing of payments.

Cash outflows for investing activities for the nine months ended September 30, 2013 were $89.0 million compared with $97.8 million for the nine months ended September 30, 2012. These outflows mainly relate to the net cash expenditures on exploration, appraisal and development activities (net of IPI cash calls) of $78.2 million, expenditures on plant and equipment of $20.1 million and a $8.6 million decrease in working capital requirements of development segments relating to the timing of payments. These outflows were partially offset by a $10.1 million decrease in restricted cash held as security under the BNP working capital facility and $7.8 million proceeds from disposal of FLEX LNG shares (net of transaction costs).

Cash flows (used in)/generated from financing activities

Cash outflows used in financing activities for the quarter ended September 30, 2013 amounted to $24.9 million, compared with the cash inflows of $50.4 million for the quarter ended September 30, 2012. The increase in the cash outflows are primarily due to the $34.4 million full settlement made in accordance to the settlement and termination deed with Mitsui after the termination of CSP JVOA, $10.7 million full repayment of Westpac secured loan and $14.4 million net repayment of working capital facilities. These cash outflows however have been partly reduced by the $34.6 million drawdown of BSP and Westpac combined secured facility during the quarter.

Cash inflows from financing activities for the nine months ended September 30, 2013 amounted to $70.3 million, compared with inflows of $113.1 million for the nine months ended September 30, 2012. These cash inflows are primarily due to a receipt of $73.6 million initial staged cash payments from PRE for interests in PPL 237; $34.6 million drawdown of BSP and Westpac combined secured facility; $13.3 million net proceeds from working capital facility; and $4.0 million proceeds from the issuance of common shares during the period following the exercise of stock options. These inflows were partially offset by the $34.4 million full settlement made in accordance to the settlement and termination deed with Mitsui after the termination of CSP JVOA, $12.9 million full repayment of Westpac secured loan (including the semi-annual loan principal repayment of $2.1 million) and the $8.0 million semi-annual principal loan repayment under the ANZ, BNP and BSP syndicated loan facility.

Management Discussion and Analysis INTEROIL CORPORATION 12

Summary of Consolidated Quarterly Financial Results for Past Eight Quarters

The following is a table containing the consolidated results for the eight quarters ended September 30, 2013 by business segment, and on a consolidated basis.

Quarters ended ($ thousands except per share	2013									2012												2011
data)	Sep-30			Jun-30			Mar-31			Dec-31			Sep-30			Jun-30			Mar-31			Dec-31
Upstream		1,918			2,533			1,862			4,136			2,216			1,727			2,284			1,891
Midstream – Refining		251,725			289,300			305,172			301,925			274,671			236,006			302,310			237,640
Midstream – Liquefaction		-			20,089			-			-			-			-			-			-
Downstream		215,651			199,470			208,046			220,512			201,749			223,620			218,974			209,678
Corporate		31,714			36,201			34,923			37,552			26,880			24,742			24,757			21,831
Consolidation entries		(195,773	)		(201,932	)		(199,672	)		(207,686	)		(178,652	)		(186,991	)		(210,174	)		(181,428	)
Total revenues		305,235			345,661			350,331			356,439			326,864			299,104			338,151			289,612
Upstream		(2,842	)		(19,478	)		(1,311	)		(873	)		956			(5,730	)		(6,374	)		665
Midstream – Refining		(3,562	)		840			12,701			12,370			13,417			(42,647	)		18,933			2,604
Midstream – Liquefaction		2,550			19,850			(123	)		192			11			672			(1,410	)		(4,129	)
Downstream		14,962			7,542			10,062			12,258			9,275			11,102			21,414			6,808
Corporate		13,446			1,745			10,044			14,133			9,841			9,975			9,188			10,134
Consolidation entries		(14,647	)		(11,146	)		(13,418	)		(12,199	)		(14,503	)		(9,871	)		(14,216	)		(11,280	)
EBITDA ⁽¹⁾		9,907			(647	)		17,955			25,881			18,997			(36,499	)		27,535			4,802
Upstream		(16,206	)		(32,046	)		(13,774	)		(13,081	)		(10,936	)		(15,532	)		(17,244	)		(9,402	)
Midstream – Refining		(11,074	)		(4,675	)		5,855			13,401			5,358			(32,969	)		11,320			15,684
Midstream – Liquefaction		2,373			19,284			(681	)		(394	)		(573	)		93			(1,969	)		(4,574	)
Downstream		9,435			4,346			6,005			7,716			5,626			6,045			13,195			3,621
Corporate		10,780			(1,701	)		7,342			10,519			7,849			8,445			6,270			7,616
Consolidation entries		(1,626	)		1,562			(744	)		384			(1,988	)		2,205			(2,136	)		252
Net (loss)/profit		(6,318	)		(13,230	)		4,003			18,545			5,336			(31,713	)		9,436			13,197
Net (loss)/profit per share (dollars)
Per Share – Basic		(0.13	)		(0.27	)		0.08			0.38			0.11			(0.66	)		0.20			0.27
Per Share – Diluted		(0.13	)		(0.27	)		0.08			0.38			0.11			(0.66	)		0.19			0.27

(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

QUARTER AND NINE MONTH PERIOD IN REVIEW

The following section provides a review of the quarter and nine months ended September 30, 2013 for each of our business segments.

UPSTREAM – QUARTER AND NINE MONTH PERIOD IN REVIEW

Upstream – Operating results	Quarter ended September 30,						Nine months ended September 30,
($ thousands)	2013			2012			2013			2012
Other non-allocated revenue		527			2,216			1,938			6,228
Inter-segment revenue - Recharges		1,391			-			4,376			-
Total revenue		1,918			2,216			6,314			6,228
Office and administration and other expenses		(2,977	)		(1,824	)		(27,780	)		(4,697	)
Exploration costs		(2,992	)		(2,056	)		(3,964	)		(14,660	)
Gain on conveyance of oil and gas properties		-			2,895			500			2,895
Foreign exchange gains/(losses)		1,209			(275	)		1,300			(914	)
EBITDA ⁽¹⁾		(2,842	)		956			(23,630	)		(11,148	)
Depreciation and amortization		(550	)		(454	)		(1,598	)		(1,201	)
Interest expense		(12,814	)		(11,438	)		(36,797	)		(31,363	)
Loss before income taxes		(16,206	)		(10,936	)		(62,025	)		(43,712	)
Income tax expense		-			-			-			-
Net loss		(16,206	)		(10,936	)		(62,025	)		(43,712	)

(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 Nine Months Ended September 30, 2013 and 2012

The following analysis outlines the key movements, the net of which primarily explains the variance in the results between the quarters and nine months ended September 30, 2013 and 2012.

	*Quarterly* *Variance* *($ millions)*	*Nine Month* *Variance* *($ millions)*

	*($5.3)*	*($18.3)*	*Net loss variance for the comparative periods primarily due to:*

Ø	($1.7)	($4.3)	Other non-allocated revenue relates to the utilization of construction and drilling related activities performed by us, including civil works and related infrastructure development associated with works within PRL 15. The reduction in other non-allocated revenue was due to lower recoveries relating to these activities.

Ø	$1.4	$4.4	Inter-segment revenue recharges relates to charges made to other segments for use of construction and logistics services.

Ø	($1.2)	($23.1)	Increase in office and administration expenses for the nine month period was mainly due to the transfer of historical development costs from the Midstream - Liquefaction segment to Upstream PRL15.

Management Discussion and Analysis INTEROIL CORPORATION 14

Ø	($0.9)	$10.7	Reduction in exploration costs incurred for seismic activity for PPL 236 during the periods. The 2012 seismic costs were in relation to the Kwalaha and Tuna seismic acquisition programs.

Ø	($2.9)	($2.4)	Decrease in gain on conveyance of oil and gas properties was mainly due to the recognition of sale of interest in PPL 237 to PRE during quarter ended September 30, 2012.

Ø	$1.5	$2.2	Increase in foreign exchange gain was mainly attributable to the unrealized exchange gain on the intercompany loan balances.

Ø	($1.4)	($5.4)	Higher interest expense due to an increase in inter-company loan balances provided to fund exploration and development activities.

MIDSTREAM - REFINING – QUARTER AND NINE MONTH PERIOD IN REVIEW

Midstream Refining – Operating results	Quarter ended September 30,						Nine months ended September 30,
($ thousands)	2013			2012			2013			2012
External sales		89,044			122,913			376,074			313,352
Inter-segment revenue - Sales		160,698			145,872			468,136			481,621
Inter-segment revenue - Recharges		1,981			5,883			1,981			17,836
Interest and other revenue		2			3			7			178
Total segment revenue		251,725			274,671			846,198			812,987
Cost of sales and operating expenses		(240,271	)		(243,920	)		(804,985	)		(788,419	)
Office and administration and other expenses		(2,545	)		(9,073	)		(6,400	)		(26,116	)
Derivative losses		(2,497	)		(4,826	)		(3,128	)		(4,727	)
Foreign exchange losses		(9,974	)		(3,435	)		(21,704	)		(4,025	)
EBITDA ⁽¹⁾		(3,562	)		13,417			9,981			(10,300	)
Depreciation and amortization		(3,425	)		(2,921	)		(9,709	)		(8,706	)
Interest expense		(2,351	)		(1,654	)		(7,040	)		(6,435	)
(Loss)/profit before income taxes		(9,338	)		8,842			(6,768	)		(25,441	)
Income tax (expense)/benefit		(1,736	)		(3,484	)		(3,125	)		9,148
Net (loss)/profit		(11,074	)		5,358			(9,893	)		(16,293	)

Gross Margin ⁽²⁾		9,471			24,865			39,225			6,554

(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”.

Management Discussion and Analysis INTEROIL CORPORATION 15

Midstream - Refining Operating Review

	Quarter ended September 30,						Nine Months ended September 30,
Key Refining Metric	2013			2012			2013			2012
Throughput (barrels per day)⁽¹⁾		26,786			23,980			27,937			23,883
Capacity utilization (based on 36,500 barrels per day operating capacity)		65	%		61	%		70	%		58	%
Cost of production per barrel	$	4.01		$	5.03		$	3.52		$	4.92
Working capital financing cost per barrel of production	$	0.67		$	0.66		$	0.52		$	0.71
Distillates as percentage of production		51.5	%		54.6	%		49.5	%		58.0	%

(1)

Throughput per day has been calculated excluding shut down days. During quarters ended September 30, 2013 and 2012, the refinery was shut down for 11 days and 9 days, respectively.

Analysis of Midstream - Refining Financial Results Comparing the Quarters and Nine Months Ended September 30, 2013 and 2012

The following analysis outlines the key movements, the net of which primarily explains the variance in the results between the quarters and nine months ended September 30, 2013 and 2012.

	*Quarterly* *Variance* *($ millions)*	*Nine* *Month* *Variance* *($ millions)*

	*($16.4)*	*$6.4*	*Net (loss)/ profit variance for the comparative periods primarily due to:*

Ø	($15.4)	$32.7	Decrease in gross margin for the quarter was mainly due to the following contributing factors: + A relatively stable crude and product prices movement during the quarter ended September 30, 2013 as compared to increasing prices in the quarter ended September 30, 2012. The average costs for Brent has increased by $9.0 per barrel in Q3 2013 as compared to the $18.0 per barrel in Q3 2012. Increase in gross margin for the nine month period was mainly due to the following contributing factors: + A relatively stable crude and product prices movement during the current nine months ended September 30, 2013 as compared to a large fall in prices during the second quarter of 2012 + A $23.8 million net realizable value write down made during the second quarter of 2012 while there was no inventory write down required during the current period + higher Naphtha sales with overall better crack spreads and premiums

Management Discussion and Analysis INTEROIL CORPORATION 16

Ø	($3.9)	($15.9)	Decrease in inter-segment recharges for the periods 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 the operation of the Napa Napa camp and all costs associated with the 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. The 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	$6.5	$19.7	Decrease in office and administrative expense mainly due to the costs associated with corporate employees in Papua New Guinea and the 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	$2.3	$1.6	Decrease in derivative losses were primarily due to losses incurred from the settlement of commodity contracts.

Ø	($6.5)	($17.7)	Increase in foreign exchange losses for the quarter ended September 30, 2013 was mainly due to the weakening of PGK against USD during the quarter ended September 30, 2013 (FX rate decreased from 0.4570 to 0.4160) compared to the same period in 2012 (FX rate decreased from 0.4840 to 0.4805). Increase in foreign exchange losses for the nine months ended September 30, 2013 was mainly due to the weakening of PGK against USD during the nine months ended September 30, 2013 (FX rate decreased from 0.4755 to 0.4160) compared to the same period in 2012 (FX rate increased from 0.4665 to 0.4805).

Ø	($0.5)	($1.0)	Increase in depreciation expenses were primarily due to depreciation charge for new projects capitalized within Midstream Refining segment.

Ø	$1.7	($12.3)	Decrease in income tax benefit for the nine month period mainly relates to higher carried forward losses recognized in prior period and the impact of unfavorable foreign exchange movements impacting temporary differences on translation of the nonmonetary assets of the refinery operation using period end rates.

Management Discussion and Analysis INTEROIL CORPORATION 17

MIDSTREAM - LIQUEFACTION – QUARTER AND NINE MONTH IN REVIEW

Midstream Liquefaction – Operating results	Quarter ended September 30,						Nine months ended September 30,
($ thousands)	2013			2012			2013			2012
				(revised) ⁽²⁾						(revised) ⁽²⁾
Inter-segment revenue - Recharges		-			-			20,089			-
Total segment revenue		-			-			20,089			-
Office and administration and other expenses		(28	)		393			(77	)		(40	)
Share of net profit/(loss) of joint venture partnership accounted for using the equity method		2,578			(382	)		2,265			(688	)
EBITDA ⁽¹⁾		2,550			10			22,277			(727	)
Interest expense		(177	)		(584	)		(1,301	)		(1,722	)
Profit/(loss) before income taxes		2,373			(574	)		20,976			(2,449	)
Income tax expense		-			-			-			-
Net profit/(loss)		2,373			(574	)		20,976			(2,449	)

	(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 Condensed Consolidated Interim Financial Statements for further details.

Analysis of Midstream - Liquefaction Financial Results Comparing the Quarters and Nine Months Ended September 30, 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.

In accordance with IFRS 11- “Joint Arrangement” (which superseded IAS 31 “Interests in Joint Ventures”), we have reclassified our involvement with PNG LNG from a jointly controlled entity to a joint venture. Our interests in PNG LNG 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 Interim Financial Statements for further details.

The following analysis outlines the key movements, the net of which primarily explains the variance in the results between the quarters and nine months ended September 30, 2013 and 2012.

	*Quarterly* *Variance* *($ millions)*	*Nine* *Month* *Variance* *($ millions)*

	*$2.9*	*$23.4*	*Net profit/(loss) variance for the comparative periods primarily due to:*

Ø	$0.0	$20.1	Increase in inter-segment revenue recharges for the nine month period 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	$3.0	$3.0	Increase in share of net profit of joint venture partnership accounted using the equity method was mainly due to the $2.6 million profit recognized on the gain on disposal of our interest in PNG LNG as a result of the agreement to equalize PacLNG’s interest in PNG LNG Inc. joint venture to their Upstream interest in PRL15.

Management Discussion and Analysis INTEROIL CORPORATION 18

DOWNSTREAM – QUARTER AND NINE MONTH IN REVIEW

Downstream – Operating results	Quarter ended September 30,						Nine months ended September 30,
($ thousands)	2013			2012			2013			2012
External sales		215,047			201,126			621,254			642,843
Inter-segment revenue - Sales		31			105			186			163
Interest and other revenue		573			518			1,727			1,337
Total segment revenue		215,651			201,749			623,167			644,343
Cost of sales and operating expenses		(195,685	)		(187,634	)		(576,372	)		(597,016	)
Office and administration and other expenses		(3,066	)		(4,639	)		(11,596	)		(13,918	)
Foreign exchange (losses)/gains		(1,938	)		(201	)		(2,634	)		8,382
EBITDA ⁽¹⁾		14,962			9,275			32,565			41,791
Depreciation and amortization		(1,187	)		(1,464	)		(3,634	)		(3,946	)
Interest expense		(536	)		(394	)		(1,220	)		(2,534	)
Profit before income taxes		13,239			7,417			27,711			35,311
Income tax expense		(3,804	)		(1,791	)		(7,926	)		(10,442	)
Net profit		9,435			5,626			19,785			24,869

Gross Margin ⁽²⁾		19,393			13,597			45,068			45,990

(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”.

Downstream Operating Review

	Quarter ended September 30,				Nine Months ended September 30,
Key Downstream Metrics	2013		2012		2013		2012
Sales volumes (millions of liters)		194.7		185.0		557.6		562.2
Average sales price per liter	$	0.95	$	0.97	$	1.08	$	1.03

Analysis of Downstream Financial Results Comparing the Quarters and Nine Months Ended September 30, 2013 and 2012

The following analysis outlines the key movements, the net of which primarily explains the variance in the results between the quarters and nine months ended September 30, 2013 and 2012.

	*Quarterly* *Variance* *($ millions)*	*Nine* *Month* *Variance* *($ millions)*

	*$3.8*	*($5.1)*	*Net profit variance for the comparative periods primarily due to:*

Ø	$5.8	($0.9)	Increase in gross margins for the quarter was a result of IPP price increases during the current quarter as opposed to price declines in the prior quarter. In addition, there has been the ICCC sanctioned annual price increase implemented in January 2013 of approximately 4%.

Management Discussion and Analysis INTEROIL CORPORATION 19

Ø	$1.6	$2.3	Decreases in office and administrative and other expenses were mainly due to major repairs works being performed in 2012.

Ø	($1.7)	($11.0)	Increase in foreign exchange losses for the nine month period mainly resulted from the weakening of PGK against USD during the nine months ended September 30, 2013, and a one-time transfer of exchange gain on translation of loan balances from other comprehensive income in equity to profit and loss upon repayment of intercompany loans during the nine months ended September 30, 2012.

Ø	($0.1)	$1.3	Decrease in interest expense for the nine month period was mainly due to lower utilization of the working capital facility during the period.

Ø	($2.0)	$2.5	Increase in income tax expense for the quarter mainly due to the higher profit before tax earned during the period. Decrease in income tax expense for the nine month period mainly due to the lower profit before tax earned during the period.

CORPORATE – QUARTER AND NINE MONTH IN REVIEW

Corporate – Operating results	Quarter ended September 30,						Nine months ended September 30,
($ thousands)	2013			2012			2013			2012
External sales		319			70			480			140
Inter-segment revenue - Sales		5,820			6,530			18,977			16,564
Inter-segment revenue - Recharges		12,864			7,780			45,328			23,066
Interest revenue		12,638			12,500			37,979			36,609
Other non-allocated revenue		73			-			73			-
Total revenue		31,714			26,880			102,837			76,379
Cost of sales and operating expenses		(5,066	)		(5,158	)		(16,070	)		(13,688	)
Office and administration and other expenses		(16,652	)		(12,195	)		(63,075	)		(34,247	)
Derivative gains/(losses)		45			(103	)		(146	)		11
Foreign exchange (losses)/gains		(1,342	)		417			(2,031	)		550
Gain on Flex LNG investment		4,747			-			3,720			-
EBITDA ⁽¹⁾		13,446			9,841			25,235			29,005
Depreciation and amortization		(932	)		(629	)		(2,720	)		(1,687	)
Interest expense		(1,842	)		(1,540	)		(5,524	)		(4,585	)
Profit before income taxes		10,672			7,672			16,991			22,733
Income tax benefit/(expense)		108			177			(571	)		(168	)
Net profit		10,780			7,849			16,420			22,565

Gross Margin ⁽²⁾		1,073			1,442			3,387			3,016

(1)

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

(2)

Management Discussion and Analysis INTEROIL CORPORATION 20

Analysis of Corporate Financial Results Comparing the Quarters and Nine Months Ended September 30, 2013 and 2012

The following analysis outlines the key movements, the net of which primarily explains the variance in the results between the quarters and nine months ended September 30, 2013 and 2012.

	*Quarterly* *Variance* *($ millions)*	*Nine Month* *Variance* *($ millions)*

	*$2.9*	*($6.1)*	*Net profit variance for the comparative periods primarily due to:*

Ø	$5.1	$22.3	Increase in inter-segment recharges for both periods 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.

Ø	$0.1	$1.4	Higher interest income due to an increase in inter-company loan balances.

Ø	($4.5)	($28.8)	Increase in office and administrative expenses mainly due to the costs associated with corporate employees in Papua New Guinea and the 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, there were non-recurring expenses of $8.7 million incurred for the retirement of senior management during the nine months ended September 30, 2013.

Ø	($1.8)	($2.6)	Increases in foreign exchange losses for both periods were primarily due to the weakening of PGK against USD. In addition, the weakening of AUD against USD for nine month period (FX rate has decreased from 1.0383 on January 1, 2013 to 0.9312 on September 30, 2013) has further contributed to the exchange losses.

Ø	$4.7	$3.7	Increase in gain on available-for-sale investment in both periods was due to the gain recognized for the disposal of FLEX LNG shares during the periods ($4.7 million in the quarter ended September 30, 2013, and $3.7 million for the nine months ended September 30, 2013 after mark to market losses taken up in the earlier quarters of the period).

Ø	($0.3)	($1.0)	Increase in depreciation expenses were primarily due to depreciation charge for the fixed assets transferred from Refinery segment to Corporate segment in December 2012.

Ø	($0.3)	($0.9)	Increase in interest expenses were primarily due to interest charged on cash calls repayable to Mitsui in quarter ended September 30, 2013.

Management Discussion and Analysis INTEROIL CORPORATION 21

CONSOLIDATION ADJUSTMENTS – QUARTER AND NINE MONTH IN REVIEW

Consolidation adjustments – Operating results	Quarter ended September 30,						Nine months ended September 30,
($ thousands)	2013			2012			2013			2012
Inter-segment revenue - Sales		(166,549	)		(152,507	)		(487,298	)		(498,347	)
Inter-segment revenue - Recharges		(16,236	)		(13,663	)		(71,773	)		(40,902	)
Interest revenue ⁽¹⁾		(12,988	)		(12,483	)		(38,308	)		(36,569	)
Total revenue		(195,773	)		(178,653	)		(597,379	)		(575,818	)
Cost of sales and operating expenses ⁽²⁾		166,839			150,382			488,186			496,165
Office and administration and other expenses ⁽³⁾		14,287			13,769			69,979			41,066
EBITDA ⁽⁴⁾		(14,647	)		(14,502	)		(39,214	)		(38,587	)
Depreciation and amortization⁽⁵⁾		32			33			98			98
Interest expense⁽¹⁾		12,989			12,482			38,308			36,568
Loss before income taxes		(1,626	)		(1,987	)		(808	)		(1,921	)
Income tax expense		-			-			-			-
Net loss		(1,626	)		(1,987	)		(808	)		(1,921	)

Gross Margin ⁽⁶⁾		290			(2,125	)		888			(2,182	)

(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 Nine Months Ended September 30, 2013 and 2012

The following table outlines the key movements, the net of which primarily explains the variance in the results between the quarters and nine months ended September 30, 2013 and 2012.

	*Quarterly* *Variance* *($ millions)*	*Nine* *Month* *Variance* *($ millions)*

	*$0.4*	*$1.1*	*Net loss variance for the comparative periods primarily due to:*

Ø	$2.4	$3.1	Variance in net loss 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	($2.0)	($2.0)	Variance in net loss 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 22

LIQUIDITY AND CAPITAL RESOURCES

Summary of Debt Facilities

Summarized below are the debt facilities available to us and the balances outstanding as at September 30, 2013.

Organization	Segment	Facility			Balance outstanding September 30, 2013			Effective interest rate			Maturity date
ANZ, BSP and BNP syndicated secured loan facility	Midstream - Refining	$	100,000,000		$	92,000,000			6.94	%	November 2017
BNP working capital facility⁽¹⁾	Midstream - Refining	$	270,000,000		$	107,584,830	⁽²⁾		2.87	%	February 2015
BNP non-recourse discounting facility⁽¹⁾	Midstream - Refining	$	80,000,000		$	0			2.87	%	February 2015
Westpac PGK working capital facility	Downstream	$	18,720,000	⁽³⁾	$	0			9.15	%	November 2014
BSP PGK working capital facility	Downstream	$	20,800,000		$	0			9.45	%	November 2014
BSP and Westpac combined secured facility	Downstream	$	75,000,000		$	34,604,377			8.89	%	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. There were no non-recourse discounted
receivables as at September 30, 2013.}

⁽²⁾

^{Excludes letters
of credit totaling $74.7 million, which reduces
the available borrowings under the facility to $87.7
million at September 30, 2013.}

⁽³⁾

^{Effective rate
after bifurcating the equity and debt components
of the $70 million principal amount of 2.75% convertible
senior notes due 2015.}

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, our 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 in the future. 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)

Subsequent to quarter end, on November 11, 2013, the Company entered into a $250.0 million secured syndicated capital expenditure facility led by Credit Suisse AG related to an approved seismic data acquisition and drilling program. In addition to Credit Suisse the participating lenders are CBA, ANZ, UBS, Macquarie, BSP, BNP Paribas and Westpac. The facility is secured by the Company’s existing Upstream and Corporate Entities. The credit facility bears interest at LIBOR plus 5.5 percent 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. The facility is payable in full (within a certain timeframe) upon any sale or disposal of the Company’s interest in the Elk and Antelope fields.

Management Discussion and Analysis INTEROIL CORPORATION 23

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

On October 16, 2012, we entered into a five year amortizing $100.0 million syndicated secured term loan facility with BNP, BSP, and ANZ. The loan is secured by the fixed assets of the refinery. The balance outstanding under the loan facility as at September 30, 2013 was $92.0 million. The interest rate on the loan is equal to LIBOR plus 6.5%. During the nine months ended September 30, 2013, the weighted average interest rate under the facility was 6.94%.

The principal of the syndicated secured loan facility is repayable in ten half yearly installments over the period of five years. The first four half yearly installments are for an amount of $8.0 million each, the next two installments are for an amount of $10.0 million each, and the final four installments are for an amount of $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 nine months ended September 30, 2013, a loan installment payment of $8.0 million was paid. As at September 30, 2013, we have two installment payments of $8.0 million each due for payment on November 9, 2013 and May 9, 2014. A cash restricted balance of $11.2 million was held on deposit as at September 30, 2013 to secure our principal installment due on November 9, 2013 and interest payments on the syndicated secured loan facility.

BNP Paribas Working Capital Facility (Midstream - Refinery)

On July 17, 2013, we entered into a $350.0 million working capital structured facility arranged by BNP Paribas to replace the $240.0 million facility. Out of the $350.0 million, $270.0 million is a syndicated secured working capital facility with the support of five banking partners, namely BNP Paribas, ANZ, Natixis, Intesa, Sanpaolo, and BSP, which includes the ability to discount receivables with recourse up to $30.0 million. In addition, BNP Paribas 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 refinery. The credit portion of the facility bears interest at LIBOR + 3.75% per annum. The facility is renewable in February 2015.

As of September 30, 2013, $107.6 million was outstanding under the facility along with $74.7 million in letters of credit, leaving $87.7 million available for use under the facility in addition to the $80.0 million bilateral non-recourse discounting facility. The facility bears interest at LIBOR plus 3.5% on short term advances. The weighted average interest rate under the working capital facility was 2.87% for the nine months ended September 30, 2013, after including the reduction in interest due to the deposit amounts (restricted cash) maintained as security.

Westpac and Bank South Pacific Working Capital Facility (Downstream)

On October 24, 2008, we secured a revolving working capital facility for our Downstream wholesale and retail petroleum products distribution business from BSP and Westpac. The Westpac facility limit was PGK 90.0 million (approximately $37.4 million). This facility was for an initial term of three years and was renewed in November 2011 for a further three years to November 2014. The Westpac facility was increased in February 2012 by PGK 10.0 million (approximately $4.2 million). The BSP facility is PGK 50.0 million (approximately $20.8 million), renewable annually and was renewed in August 2013 through to November 2014.

The downstream working capital facilities with BSP and Westpac have been underutilized, due to the downstream division’s prudent working capital management initiatives and strong liquidity. As such, BSP and Westpac agreed to channel existing downstream approved limits of PGK 45.0 million (approximately $18.7 million) to the BSP and Westpac combined secured facility and this working capital facility limit was decreased by PGK 45.0 million (approximately $18.7 million). The facility limit as at September 30, 2013 for Westpac PGK working capital facility was PGK 45.0 million (approximately $18.7 million) and BSP PGK working capital facility was PGK 50.0 million (approximately $20.8 million).

As at September 30, 2013, none of this combined facility had been utilized, and the full amount of the facility remained available for use. These facilities are secured by a fixed and floating charge over the assets of Downstream operations.

Management Discussion and Analysis INTEROIL CORPORATION 24

The weighted average interest rate under the Westpac facility was 9.15% and the weighted average interest rate under the BSP facility was 9.45% as at September 30, 2013.

Bank South Pacific and Westpac Combined Secured Facility (Downstream)

On August 19, 2013, we entered into a one year $75.0 million equivalent combined secured loan facility with Westpac and BSP to be drawn in tranches, either USD and/or PGK. Borrowings under the facility will be used for exploration and drilling activities with $37.5 million available immediately, and a further $37.5 million to be available upon the execution of an agreement in relation to the monetization of the Elk and Antelope resource. The principal repayment will be made on the earlier of, the first resource payment or 12 months from the first drawdown. This facility is secured against our Downstream assets and undertakings. As at September 30, 2013, $34.6 million of the facility had been utilized. The weighted average interest rate under this facility was 8.89% for the nine months ended September 30, 2013.

Subsequent to the quarter end, the entire $37.5 million of the first tranche was fully drawn down, and after the Credit Suisse facility closed, the second tranche of $37.5 million was cancelled.

2.75% Convertible Notes (Corporate)

On November 10, 2010, we completed the issuance of $70.0 million unsecured 2.75% convertible notes with a maturity of five years. The convertible notes rank junior to any secured indebtedness and to all existing and future liabilities of us and our subsidiaries, including the BNP working capital facility, the ANZ, BSP and BNP syndicated secured loan facility, the Westpac secured loan facility, the BSP and Westpac working capital facilities, the Mitsui preliminary financing agreement, 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 upon our current shareholders not otherwise available to the convertible notes. Upon conversion, holders will receive cash, common shares or a combination thereof, at our option. The convertible notes are redeemable at our option if our share price has been at least 125% ($119.53 per share) of the conversion price for at least 15 trading days during any 20 consecutive trading day period. Upon a fundamental change, which would include a change of control, holders may require us to repurchase their convertible notes for cash at a purchase price equal to the principal amount of the notes to be repurchased, plus accrued and unpaid interest.

During the nine months ended September 30, 2013, $2,000 of the convertible notes were converted into cash.

Westpac Secured Loan (Downstream)

A secured loan of $15,000,000 was provided as part of the increased Westpac working capital facility which was repayable in equal installments over 3.5 years with an interest rate of LIBOR + 4.4% per annum. The loan was secured by a fixed and floating charge over the assets of Downstream operations. The loan was fully repaid during the quarter ended September 30, 2013.

Mitsui Unsecured Loan (Upstream)

On April 15, 2010, we entered into preliminary joint venture and financing agreements with Mitsui relating to the Condensate Stripping Project. On August 4, 2010, we entered into the CSP Joint Venture with Mitsui for the development of the condensate stripping facilities. Mitsui and InterOil held equal interest in the joint venture. On July 16, 2013, we entered into a Settlement and Termination Deed with Mitsui following the termination of the CSP JVOA on February 28, 2013. In accordance with the deed, we repaid Mitsui $34.4 million in relation to the cancellation of option to acquire interests in the Elk and Antelope fields, and Mitsui’s share of capital expenditure incurred on the condensate stripping facilities, the unsecured loan, together with interest thereon. The facility has now been fully repaid, and all security provided to Mitsui discharged.

Management Discussion and Analysis INTEROIL CORPORATION 25

Other Sources of Capital

Currently our share of expenditures on exploration wells, appraisal wells and extended well programs is funded by a combination of contributions made by capital raising activities, 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 amounts spent on certain appraisal wells and extended well programs where they participate in such wells and programs pursuant to the relevant agreements in place 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 executed a farm-in agreement with PRE for PRE to be able to earn a 10.0% net (12.9% gross) participating interest in the PPL 237 onshore Papua New Guinea, including the Triceratops structure located within that license. The transaction contemplates staged initial cash payments totaling $116.0 million, an additional carry of 25% of the costs of an agreed exploration work program, and a final resource payment. As at September 30, 2013, PRE has paid the full amount of the staged cash payments ($116.0 million), being $96.0 million paid in accordance with the farm-in agreement, and the Initial Cash Payment of $20.0 million. The $96.0 million of the staged cash payment is refundable if PRE decides to exit the program, with the payment to be refunded within six years.

Summary of Cash Flows

	Quarter ended September 30,						Nine months ended September 30,
($ thousands)	2013			2012			2013			2012
				(revised)						(revised)
Net cash (outflows)/inflows from:
Operations		26,140			24,902			9,500			(27,860	)
Investing		(25,626	)		(38,564	)		(89,042	)		(97,774	)
Financing		(24,929	)		50,381			70,260			113,150
Net cash movement		(24,415	)		36,719			(9,282	)		(12,484	)
Opening cash		64,842			20,435			49,721			68,575
Exchange (losses)/gains on cash and cash equivalents		(22	)		(2	)		(34	)		1,061
Closing cash		40,405			57,152			40,405			57,152

Analysis of Cash Flows Generated From/(Used In) Operating Activities Comparing the Quarters and Nine Months Ended September 30, 2013 and 2012

The following table outlines the key variances in the cash inflows/(outflows) from operating activities between the quarters and nine months ended September 30, 2013 and 2012:

Quarterly

variance

($ millions)

Nine Month

variance

($ millions)

$1.2

$37.4

Variance for the comparative periods primarily due to:

Management Discussion and Analysis INTEROIL CORPORATION 26

$8.7

$19.8

Increase in cash generated from operations prior to changes in operating working capital for the quarter ended September 30, 2013, mainly due to the decrease in inventory write down; and offset by the increase in net loss from operation adjusted for the increased gain on FLEX LNG investment.

Increase in cash generated from operations prior to changes in operating working capital for the nine months ended September 30, 2013, mainly due to the decrease in net loss from operations adjusted for decrease in future income tax benefit; and offset by the increase in gain on FLEX LNG investment and increase in share of net profit of joint venture partnership.

($7.4)

$17.5

Decrease in cash generated from operations relating to changes in operating working capital for the quarter. The movement was due primarily to a $72.0 million increase in inventories due to timing of crude and export shipments, a $6.4 million increase in other current assets and prepaid expenses and a $1.8 million increase in accounts payable and accrued liabilities; and partially offset by a $72.8 million decrease in trade and other receivables.

Decrease in cash used in operations relating to changes in operating working capital for the nine month period. The movement was due primarily to a $33.2 million decrease in trade and other receivables and a $5.8 million decrease in inventories; and partially offset by a $19.6 million decrease in accounts payable and accrued liabilities and a $1.9 million increase in other current assets and prepaid expenses.

Analysis of Cash Flows Used In Investing Activities Comparing the Quarters and Nine Months Ended September 30, 2013 and 2012

The following table outlines the key variances in the cash outflows from investing activities between the quarters and nine months ended September 30, 2013 and 2012:

	*Quarterly* *variance* *($ millions)*	*Nine Month* *variance* *($ millions)*

	*$12.9*	*$8.7*	*Variance for the comparative periods primarily due to:*

Ø	$5.6	$29.4	Lower cash outflows on exploration and development program expenditures mainly due to a reduction in drilling activities.

Ø	$12.0	$23.6	Higher cash calls and related inflows from joint venture partners relating to the Triceratops-2 well and historical infrastructure costs.

Ø	($0.8)	$0.9	Movements in expenditure on plant and equipment were mainly due to movement of expenditure on plant and equipment in Downstream, Midstream-Refinery and Corporate segments. The expenditures made incurred during the periods were mainly associated with tanks, the CRU, and upgrade of projects across fuel stations, terminals and depots.

Ø	$0.0	($20.0)	A $20.0 million initial staged cash payment was received from PRE for the sell down of 10% net (12.9% gross) interest in PPL237 during the nine months ended September 30, 2012.

Ø	$0.0	($11.8)	Maturity of short term PGK Treasury bills during the nine months ended September 30, 2012.

Ø	$7.8	$7.8	Proceeds from disposal of Flex LNG shares, net of transaction costs.

Management Discussion and Analysis INTEROIL CORPORATION 27

($7.1)

$10.4

Higher cash outflows for the quarter was mainly relate to the increase in our cash restricted balance held under the BNP working capital facility due to higher utilization of the working capital facility during the period.

Higher cash inflows for the nine month period was mainly relate to the decrease in our cash restricted balance held under the BNP working capital facility due to lower utilization of the working capital facility during the period.

($4.6)

($31.5)

Movement in non-operating working capital for the quarter relating to accounts payable and accruals in our Upstream operations.

Movement in non-operating working capital for the nine month period relating to trade and other receivables, and accounts payable and accruals in our Upstream operations.

Analysis of Cash Flows (Used In)/ Generated From Financing Activities Comparing the Quarters and Nine Months Ended September 30, 2013 and 2012

The following table outlines the key variances in the cash (outflows)/inflows from financing activities between quarters and nine months ended September 30, 2013 and 2012:

	*Quarterly variance* *($ millions)*	*Nine Month variance* *($ millions)*

	*($75.3)*	*($42.9)*	*Variance for the comparative periods primarily due to:*

Ø	$0.0	$4.5	Repayment of OPIC loan principal installment during the nine months ended September 30, 2012.

Ø	($38.0)	($38.0)	Termination settlement to Mitsui for the Condensate Stripping Project funding provided by Mitsui and related interests.

Ø	($8.6)	($25.7)	Full settlement of the outstanding secured loan from Westpac during both periods.

Ø	$34.6	$34.6	Drawdown of the $34.6 million secured loan facility from BSP and Westpac during the quarter and nine months ended September 30, 2013.

Ø	($20.0)	$53.6	A $20.0 million initial staged cash payment was received from PRE for the sell down of 10% net (12.9% gross) interest in PPL237 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	($38.6)	($57.3)	Movement in utilization of the BNP Paribas working capital facility is due to movement in working capital requirements.

Ø	$0.0	($8.0)	Repayment of ANZ, BSP and BNP semi-annual syndicated loan principal installment during the nine months ended September 30, 2013.

Ø	($4.8)	($6.6)	Movements were due to the lower receipts of cash from the exercise of stock options during the quarter and nine months ended September 30, 2013.

Management Discussion and Analysis INTEROIL CORPORATION 28

Capital Expenditures

Upstream Capital Expenditures

Capital expenditures for our Upstream segment in Papua New Guinea for the quarter ended September 30, 2013 were $31.2 million, compared with $20.7 million during the same period of 2012. Total net expenditures for the nine month period ended September 30, 2013 were $59.1 million compared to $109.2 million during the same period in 2012.

The following table outlines the key expenditures in the quarter and nine months ended September 30, 2013:

	*Quarterly* *($ millions)*	*Nine Month* *($ millions)*

	*$31.2*	*$59.1*	*Expenditures in the quarter and nine months ended September 30, 2013 primarily due to:*

Ø	($0.9)	$6.2	Costs incurred for site preparation, pre-spud and drilling works at the Antelope-3 well site.

Ø	$0.8	$7.1	Costs incurred for Elk-3 well site preparation, spud works, drilling and standby works.

Ø	$0.0	$4.0	Costs incurred for Herd Base to Antelope field road construction and maintenance (South Road).

Ø	$0.1	$1.6	Costs for works at Hou Creek, which includes the construction of a complex in the north of the Elk and Antelope fields. The complex includes facilities such as wharf, camp, warehouse and related earth works.

Ø	$0.0	$4.6	Costs incurred for Herd Base to Antelope field road construction (North Road). The road is to connect the Hou Creek complex to the Antelope-2 well and to the south road which commences at Herd Base.

Ø	$0.0	$6.0	Project management teams’ costs and sub-contractors costs incurred for the LNG Project, including costs incurred for pipeline works, which mainly consists of work done by technical consultants on geotechnical survey, centerline survey and field to coast pipeline FEED, and costs for works in respect of the Condensate Stripping Project, which mainly includes the costs incurred for submittal and evaluation of the revised tender. Note that work on these projects has now ceased and there were no costs incurred during the quarter ended September 30, 2013.

Ø	$14.4	$39.8	Recoveries in relation to the drilling services, construction equipment, labor, logistics and warehousing services provided due to reduced activities during the periods.

Ø	$2.2	$2.2	Seismic incurred over the Triceratops field in PPL 237.

Ø	($0.0)	($14.1)	Allocation of historical Triceratops-2 well costs to PRE (net of credits given to other joint venture partners).

Ø	$2.3	($12.9)	Allocation of historical northern infrastructure costs in the Elk and Antelope fields to joint venture partners.

Ø	$11.0	$11.0	Costs accrued in relation to the fees payable to our financial advisor in relation to the monetization of the Elk and Antelope fields.

Management Discussion and Analysis INTEROIL CORPORATION 29

$1.3

$3.6

Other expenditures, including equipment purchases and drilling inventory.

Midstream – Refining Capital Expenditures

Capital expenditures totaled $5.2 million in our Midstream - Refining segment for the nine months ended September 30, 2013, mainly associated with boiler, mercury removal project and other minor upgrade works.

Downstream Capital Expenditures

Capital expenditures for the Downstream segment totaled $4.1 million for the nine months ended September 30, 2013. These expenditures mainly related to the upgrade projects across various fuel stations, terminals and depots.

Capital Requirements

The oil and gas exploration and development, refining and liquefaction industries are capital intensive and our business plans necessitate raising of additional capital. The availability and cost of such capital is highly dependent on market conditions at the time 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 given current market volatility.

The majority of our “net cash from operating activities” adjusted for “proceeds from/(repayments of) working capital facilities” is used in our appraisal and development programs for the Elk, Antelope, and Triceratops fields in Papua New Guinea. Our net cash from operating activities is not sufficient to fund those appraisal and development programs, the LNG Project or the Condensate Stripping Project.

Upstream

We are required under our IPI Agreement to drill eight exploration wells. We have drilled four wells to date. As at September 30, 2013, we are committed under the terms of our exploration licenses or PPL’s to spend a further $48.2 million through 2014. As at September 30, 2013, management estimates that satisfying these license commitments with the expenditure of $48.2 million would also satisfy our commitments to the IPI investors in relation to drilling the final four wells required under the IPI Agreement. The actual aggregate cost of drilling the final four exploration wells in relation to the IPI Agreement may ultimately end up costing us more than what is required to satisfy our license commitments.

In addition, the terms of the grant of PRL 15 require us to spend $73.0 million on the development of the Elk and Antelope fields 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 $472.1 million on PRL 15 which includes seismic, Herd Base/Hou Creek wharf and camps, roads, FEED for wells, gas gathering, condensate stripping, and pipelines. $32.4 million of the expenditures to date relates to the $79.5 million commitment. Expenditure on the drilling of further delineation wells for the development of our PRL15 resource will meet our well commitment requirements under the license.

We do not have sufficient funds to complete planned exploration and development activities and we will need to raise additional funds in order for us to complete the 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 sufficient cash to meet these obligations over time and complete these long term plans. No assurances can be given that we will be successful in obtaining new capital on terms acceptable to us, or at all, particularly given recent market volatility.

We will also be required to obtain substantial amounts of financing for the development of the Elk, Antelope and Triceratops fields, condensate stripping and associated facilities, pipelines and LNG export terminal facilities, and it will take a number of years to complete these projects. In the event that positive FID is reached in respect of these projects, we seek to be in a position to access the capital markets and/or sell an interest in our upstream properties in order to raise adequate capital. We have retained financial advisors to help solicit and evaluate proposals from potential strategic partners to acquire interests in the monetization of the Elk and Antelope fields, which will include the development of a condensate stripping facility, pipelines, liquefaction facilities and storage and loading facilities. Our exclusivity agreement with ExxonMobil Papua New Guinea, a subsidiary of ExxonMobil, in connection with negotiations for the development of our PRL15 resource expired on July 25, 2013. Although negotiations regarding the development of this resource are ongoing, we can give no assurances that we will be successful in completing a transaction on terms acceptable to us or at all.

Management Discussion and Analysis INTEROIL CORPORATION 30

The availability and cost of various sources of financing is highly dependent on market conditions and our condition at the time we raise such capital and we can provide no assurances that we will be able to obtain such financing or conduct such sales on terms that are acceptable.

Midstream - Refining

We believe that we will have sufficient funds from our operating cash flows to pay our estimated capital expenditures associated with our Midstream - Refining segment in 2013. We also believe cash flows from operations will be sufficient to cover the costs of operating our refinery and the financing charges incurred under our crude import facility. Should there be long term deterioration in refining margins, our refinery may not generate sufficient cash flows 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 in the future.

Midstream - Liquefaction

Completion of liquefaction facilities and associated infrastructure will require substantial amounts of financing and construction will take a number of years to complete. As a joint venture partner in development, if the project is completed, we would be required to fund our share of facilities of the development. No assurances can be given that we will be able to source sufficient gas, successfully construct such a facility, or as to the timing of such construction. The availability and cost of capital is highly dependent on market conditions and our circumstances at the time we raise such capital.

Downstream

We believe on the basis of current market conditions and the status of our business that our cash flows from operations will be sufficient to meet our estimated capital expenditures for our wholesale and retail distribution business segment for 2013. Should there be a major long-term deterioration in wholesale or retail margins, our Downstream operations may not generate sufficient cash flows 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

The following table contains information on payments required to meet contracted exploration and debt obligations due for each of the next five years and thereafter. It should be read in conjunction with our Condensed Consolidated Interim Financial Statements and the notes thereto:

	Payments Due by Period
Contractual obligations ($ thousands)	Total		Less than 1 year		1 - 2 years		2 - 3 years		3 - 4 years		4 - 5 years		More than 5 years
Petroleum prospecting and retention licenses ⁽¹⁾		95,216		95,216		-		-		-		-		-
Secured and unsecured loans		143,892		56,751		22,982		25,668		26,076		12,415		-
2.75% Convertible notes obligations		74,171		1,925		1,925		70,321		-		-		-
Indirect participation interest - PNGDV		1,384		1,384		-		-		-		-		-
Total		314,663		155,276		24,907		95,989		26,076		12,415		-

Management Discussion and Analysis INTEROIL CORPORATION 31

(1)

The amount pertaining to the petroleum prospecting and retention licenses represents the amount we have committed as a condition on renewal of these licenses. We are committed to spend a further $48.2 million as a condition of renewal of our petroleum prospecting licenses through 2014 under our exploration licenses. As at September 30, 2013, management estimates that satisfying this license commitment with the expenditure of $48.2 million would also satisfy our commitments to the IPI investors in relation to drilling the final four exploration wells required under the IPI agreement. In addition, 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 2014.

Off Balance Sheet Arrangements

Neither during the nine months ended, nor as at September 30, 2013, did we have any off balance sheet arrangements or any relationships with unconsolidated entities or financial partnerships.

Transactions with Related Parties

(a) Key management compensation

During the nine months ended September 30, 2013, two of our executive officers, former CEO, Phil Mulacek and former Executive VP, Christian Vinson, retired. The compensation paid or payable to these officers upon their retirement was $7.2 million and $1.5 million respectively.

(b) Phil Mulacek consultancy services

Phil Mulacek, a director of InterOil, provided advisory services to us during the nine months ended September 30, 2013. The agreement with Phil Mulacek allows for the provision of advisory services to us from May 1, 2013 to December 31, 2013 at a cost of $25,000 per month. Amounts paid or payable to Phil Mulacek for advisory services during the nine months ended September 30, 2013 amounted to $125,000.

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 September 30, 2013, we had 48,824,038 common shares (50,503,804 common shares on a fully diluted basis) and no preferred shares issued and outstanding. The potential dilutive instruments outstanding as at September 30, 2013 included employee stock options and restricted stock in respect of 947,762 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 November 11, 2013, we had 48,930,054 common shares (50,603,510 common shares on a fully diluted basis) and no preferred shares issued and outstanding. The potential dilutive instruments outstanding as at November 11, 2013 included employee stock options and restricted stock in respect of 941,452 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 feedstocks can be volatile and sometimes experience large fluctuations over periods of time as a result of relatively small changes in supplies, weather conditions, 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 and its arrival at the refinery and the supply of finished products to the various markets.

Generally, we purchase crude feedstock two months in advance, whereas the supply/export of finished products will take place after the crude feedstock is discharged and processed. Due to the fluctuation in prices during this period, we use various derivative instruments as a tool to reduce the risks of changes in the relative prices of our crude feedstocks and refined products. These derivatives, which we use to manage our price risk, effectively enable us to lock-in the refinery margin such that we are protected in the event that the difference between our sale price of the refined products and the acquisition price of our crude feedstocks contracts is reduced. 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 feedstocks expands or increases, then the benefits would be limited to the locked-in margin.

Management Discussion and Analysis INTEROIL CORPORATION 32

The derivative instruments which we generally use are over-the-counter swaps. The swap transactions are concluded between counterparties in the derivatives swaps market, unlike futures which are transacted on the Intercontinental Exchange and NYMEX Exchanges. We believe these hedge counterparties to be credit worthy. It is common place among refiners and trading companies in the Asia Pacific market to use derivatives swaps as a tool to hedge their price exposures and margins. Due to the wide usage of derivatives tools in the Asia Pacific region, the swaps market generally provides sufficient liquidity for hedging and risk management activities. The derivatives swap instrument covers commodities or products such as jet and kerosene, diesel, naphtha, and also bench-mark crudes such as Tapis and Dubai. By using these tools, we actively engage in hedging activities to lock in margins. Occasionally, there is insufficient liquidity in the crude swaps market and we then use other derivative instruments such as Brent futures on the Intercontinental Exchange to hedge our crude costs.

At September 30, 2013, we had a net payable of $0.6 million (September 30, 2012 – $0.4 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, and the swaps that have been priced out as of September 30, 2013 and will be settled in future.

RISK FACTORS

Our business operations and financial position are subject to a range of risks. A summary of the key risks that may impact upon the matters addressed in this document have been included under section “Forward Looking Statements” above. Detailed risk factors can be found under the heading “Risk Factors” in our 2012 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 the amounts reported in the Condensed Consolidated Interim 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 Condensed Consolidated Interim Financial Statements as estimating it is impracticable. During the quarter ended September 30, 2013, there were no changes in the critical accounting estimates disclosed in our annual management discussion and analysis for the year ended December 31, 2012.

However, we would like to highlight that we have a total of approximately $370.0 million temporary differences and carried forward losses in relation to exploration expenditures incurred in Papua New Guinea as at September 30, 2013. No deferred tax assets have been recognized for these exploration expenditures as at September 30, 2013. Management will consider the recognition of the deferred tax assets once the sale and purchase agreement for monetization of resources from the PRL 15 license with ExxonMobil is executed. The initial tax benefit to be recognized would be 30% of the temporary differences and losses carried forward through the income statement.

For a discussion of those accounting policies, please refer to Note 2 of the notes to our audited annual consolidated financial statements for the year ended December 31, 2012, available at www.sedar.com, which summarizes our significant accounting policies.

Management Discussion and Analysis INTEROIL CORPORATION 33

NEW ACCOUNTING STANDARDS

New accounting standards not yet applicable as at September 30, 2013

The following 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, 2015): This addresses the classification and measurement of financial assets. The standard is not applicable until January 1, 2015 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.

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”. The following table reconciles sales and operating revenues, a GAAP measure, to gross margin:

Consolidated – Operating results	Quarter ended September 30,						Nine months ended September 30,
($ thousands)	2013			2012			2013			2012
Midstream – Refining		249,742			268,785			844,210			794,973
Downstream		215,078			201,231			621,440			643,006
Corporate		6,139			6,600			19,457			16,704
Consolidation Entries		(166,549	)		(152,507	)		(487,298	)		(498,347	)
Sales and operating revenues		304,410			324,109			997,809			956,336
Midstream – Refining		(240,271	)		(243,920	)		(804,985	)		(788,419	)
Downstream		(195,685	)		(187,634	)		(576,372	)		(597,016	)
Corporate ⁽¹⁾		(5,066	)		(5,158	)		(16,070	)		(13,688	)
Consolidation Entries		166,839			150,382			488,186			496,165
Cost of sales and operating expenses		(274,183	)		(286,330	)		(909,241	)		(902,958	)
Midstream – Refining		9,471			24,865			39,225			6,554
Downstream		19,393			13,597			45,068			45,990
Corporate ⁽¹⁾		1,073			1,442			3,387			3,016
Consolidation Entries		290			(2,125	)		888			(2,182	)
Gross Margin		30,227			37,779			88,568			53,378

(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.

Management Discussion and Analysis INTEROIL CORPORATION 34

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

Quarters ended	2013									2012												2011
($ thousands)	Sep-30			Jun-30			Mar-31			Dec-31			Sep-30			Jun-30			Mar-31			Dec-31
Upstream		(2,842	)		(19,478	)		(1,311	)		(873	)		956			(5,730	)		(6,374	)		665
Midstream – Refining		(3,562	)		840			12,701			12,370			13,417			(42,647	)		18,933			2,604
Midstream – Liquefaction		2,550			19,850			(123	)		192			11			672			(1,410	)		(4,129	)
Downstream		14,962			7,542			10,062			12,258			9,275			11,102			21,414			6,808
Corporate		13,446			1,745			10,044			14,133			9,841			9,975			9,188			10,134
Consolidation Entries		(14,647	)		(11,146	)		(13,418	)		(12,199	)		(14,503	)		(9,871	)		(14,216	)		(11,280	)
Earnings before interest, taxes, depreciation and amortization		9,907			(647	)		17,955			25,881			18,997			(36,499	)		27,535			4,802
Subtract:
Upstream		(12,814	)		(12,043	)		(11,941	)		(11,734	)		(11,438	)		(10,517	)		(9,408	)		(8,712	)
Midstream – Refining		(2,351	)		(2,235	)		(2,454	)		(11,390	)		(1,654	)		(2,011	)		(2,771	)		(3,285	)
Midstream – Liquefaction		(177	)		(566	)		(558	)		(586	)		(584	)		(579	)		(559	)		(445	)
Downstream		(536	)		(263	)		(422	)		(337	)		(394	)		(909	)		(1,233	)		(1,170	)
Corporate		(1,842	)		(2,081	)		(1,600	)		(1,601	)		(1,540	)		(1,535	)		(1,510	)		(1,498	)
Consolidation Entries		12,989			12,677			12,642			12,552			12,482			12,044			12,047			11,500
Interest expense		(4,731	)		(4,511	)		(4,333	)		(13,096	)		(3,128	)		(3,507	)		(3,434	)		(3,610	)
Upstream		-			-			-			-			-			-			-			-
Midstream – Refining		(1,736	)		(118	)		(1,270	)		16,574			(3,484	)		14,580			(1,948	)		19,243
Midstream – Liquefaction		-			-			-			-			-			-			-			-
Downstream		(3,804	)		(1,667	)		(2,455	)		(3,070	)		(1,791	)		(2,907	)		(5,746	)		(595	)
Corporate		108			(483	)		(196	)		(1,330	)		177			535			(880	)		(493	)
Consolidation Entries		-			-			-			-			-			-			-			-
Income taxes		(5,432	)		(2,268	)		(3,921	)		12,174			(5,098	)		12,208			(8,574	)		18,155
Upstream		(550	)		(525	)		(522	)		(474	)		(454	)		715			(1,462	)		(1,355	)
Midstream – Refining		(3,425	)		(3,162	)		(3,122	)		(4,153	)		(2,921	)		(2,891	)		(2,894	)		(2,878	)
Midstream – Liquefaction		-			-			-			-			-			-			-			-
Downstream		(1,187	)		(1,266	)		(1,180	)		(1,135	)		(1,464	)		(1,241	)		(1,240	)		(1,422	)
Corporate		(932	)		(882	)		(906	)		(683	)		(629	)		(530	)		(528	)		(527	)
Consolidation Entries		32			31			32			31			33			32			33			32
Depreciation and amortisation		(6,062	)		(5,804	)		(5,698	)		(6,414	)		(5,435	)		(3,915	)		(6,091	)		(6,150	)
Upstream		(16,206	)		(32,046	)		(13,774	)		(13,081	)		(10,936	)		(15,532	)		(17,244	)		(9,402	)
Midstream – Refining		(11,074	)		(4,675	)		5,855			13,401			5,358			(32,969	)		11,320			15,684
Midstream – Liquefaction		2,373			19,284			(681	)		(394	)		(573	)		93			(1,969	)		(4,574	)
Downstream		9,435			4,346			6,005			7,716			5,626			6,045			13,195			3,621
Corporate		10,780			(1,701	)		7,342			10,519			7,849			8,445			6,270			7,616
Consolidation Entries		(1,626	)		1,562			(744	)		384			(1,988	)		2,205			(2,136	)		252
Net (loss)/profit per segment		(6,318	)		(13,230	)		4,003			18,545			5,336			(31,713	)		9,436			13,197

Management Discussion and Analysis INTEROIL CORPORATION 35

PUBLIC SECURITIES FILINGS

You may access additional information about us, including our 2012 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.

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 period 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, 2012 for the foregoing purposes.

It should be noted that while our Chief Executive Officer and Chief Financial Officer believe that our disclosure controls and procedures provide a reasonable level of 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, 2012, for the foregoing purpose.

No material change in our internal controls over financial reporting were identified during the nine months ended September 30, 2013, that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

It should be noted that a control system, including our disclosure and internal controls and procedures, no matter how well conceived can provide only reasonable, but not absolute, assurance that the objectives of the control system will be met 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 36

GLOSSARY OF TERMS

“AUD” means Australian dollars.

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

“APRL” means Application for Petroleum Retention License, the application for 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.

“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.

“Condensate” A component of natural gas which is a liquid at surface conditions.

“Condensed Consolidated Interim Financial Statements” means the unaudited condensed consolidated interim financial statements for the quarter and nine months ended September 30, 2013.

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

“Crack spread” 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” 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.

“EBITDA” 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.

Management Discussion and Analysis INTEROIL CORPORATION 37

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

“FID” means 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.

“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 the Amended and Restated Indirect Participation Agreement dated February 25, 2005, as amended.

“IPI holders” means investors holding IPIs in certain exploration wells required to be drilled pursuant to the IPI Agreement.

“Jet A1” means a kerosene-type fuel, similar to jet A fuel, whose freezing point is −50°C, while its flash point is above 37.8°C. It often contains a static dissipater additive that makes it suitable for use in very low temperatures.

“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.

“LNGL” means Liquid Niugini Gas Limited, a wholly owned subsidiary of PNG LNG, incorporated under the laws of in Papua New Guinea to contract with the State and pursue the LNG Project, including construction of the proposed liquefaction facilities.

“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.

“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 isomerisation 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.

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“NI 51-101” means National Instrument 51-101 Standards for Disclosure of Oil and Gas Activities.

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

“OSE” means Oil Search Limited is a company incorporated in Papua New Guinea. The company is the largest oil and gas producer and operates all of Papua New Guinea's currently producing oil and gas fields.

“PacLNG” means Pacific LNG Operations Ltd., a company incorporated under the laws of the Bahamas.

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

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

“PNG LNG” means PNG LNG, Inc., a joint venture company established in 2007. Shareholders are InterOil LNG Holdings Inc., a wholly-owned subsidiary of InterOil, and PacLNG.

“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.

“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.

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

“Westpac” means Westpac Bank PNG Limited.

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