InterOil Corporation Management
Discussion and Analysis   For the quarter and six months ended June 30, 2013
August 12, 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 IN REVIEW	14
LIQUIDITY AND CAPITAL RESOURCES	22
RISK FACTORS	32
CRITICAL ACCOUNTING ESTIMATES	32
NEW ACCOUNTING STANDARDS	33
NON-GAAP MEASURES AND RECONCILIATION	33
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 six months ended June 30, 2013. This MD&A was prepared by management and provides a review of our performance in the quarter and six months ended June 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 June 30, 2013 and for the quarter and six months ended June 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 finance the construction and development of the LNG Project and the Condensate Stripping Project; 

· our ability to negotiate definitive agreements following conditional agreements or heads of agreement relating to the development of the LNG Project and the Condensate Stripping Project, or to otherwise negotiate and secure arrangements with other entities for such development and the associated financing thereof;

· 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 construct and commission the LNG Project and the Condensate Stripping Project together with the construction of the common facilities and pipelines, on time and within budget;

· our ability to obtain and maintain necessary permits, concessions, licenses and approvals from relevant State authorities to develop our gas and condensate resources and to develop the LNG Project and the Condensate Stripping Project 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;

Management Discussion and Analysis   INTEROIL CORPORATION   2

· 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.

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 information contained in this MD&A is made as of the date hereof and, except as required by applicable law, we will not update publicly or revise any of this forward-looking information. The forward-looking information contained in this report is 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 June 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.  Developing infrastructure for the Elk and Antelope fields which includes wells, gas gathering pipelines, condensate stripping facilities and pipelines to monetize natural gas and condensates. This segment also conducts appraisal drilling of the Triceratops field and manages our construction business which services our development projects underway in Papua New Guinea.
Midstream	Refining – Produces refined petroleum products at Napa Napa in Port Moresby, Papua New Guinea for the domestic market and for export. Liquefaction – Developing 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.  General and administrative and integrated costs are recovered from business segments on an equitable basis.  This segment also manages our shipping business which currently operates two vessels transporting 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 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

· PRE paid $4.2 million of sunk costs in connection with the Triceratop-2 well pursuant to the farm-in agreement. Subsequent to the quarter end, a further $4.2 million was received.

· On May 24, 2013, we and PacLNG entered into exclusive negotiations with ExxonMobil for the development of our PRL15 resource. The transaction has been discussed with the Government of Papua New Guinea in general terms and any future agreement will be subject to Papua New Government approval. Items under consideration in those negotiations include:

– InterOil and PacLNG selling to ExxonMobil an interest in PRL 15 that is sufficient to supply gas to develop an additional LNG train at ExxonMobil’s Konebada site. There will be staged payments before and after production commences.

– InterOil and PacLNG will be funded to drill additional delineation wells in the Elk and Antelope fields, which will be followed by certification of the resource. The resource recertification will be used to determine the economic interest of ExxonMobil in the license.

– We will have the optionality to either independently develop a second LNG project in the Gulf Province that may also use gas from PRL 15, and potentially other discoveries, such as Triceratops, or pursue further development with ExxonMobil.

· On May 15, 2013, a decision was made to warm stack Rig-3 at Elk-3, which means that although the rig is idle, it remains operational and can be quickly deployed.

· As at June 30, 2013, we had an amount of $369.6 million temporary differences and carried forward losses in relation to exploration expenditures incurred in Papua New Guinea. No deferred tax assets have been recognized for these exploration expenditures as at June 30, 2013, however, management will consider the recognition of the deferred tax assets if agreement is reached on the monetization of resources from the PRL 15 license. The tax benefit to be recognized through the income statement would result in a profit of $110.9 million being recognized.

· Rig-2 was demobilized from the Antelope-3 well location back to Herd Base for consolidation of camp locations, further sand blasting and repainting of rig components.

· We entered into a contract to acquire up to 66 kilometers of seismic lines on behalf of OSE in the combined seismic shoot over PPL338 (OSE) and our PPL237 acreage. We will act as the operator of the work program under a data sharing and joint processing arrangement.

· Further to the collaborative program with OSE, we with PRE and other partners will progress plans to acquire two further appraisal seismic lines in the Triceratops field to further define future drilling targets.

· Subsequent to quarter end, 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, which requires InterOil to make certain payments to Mitsui. On July 3, 2013, we paid Mitsui $6.3 million in relation to the call option, and $9.5 million on July 31, 2013 being the first of three equal installments in relation to Mitsui’s share of capital expenditure incurred, and the repayment of the unsecured loan, together with interest thereon. The remaining two installments will be paid on August 31, 2013 and September 30, 2013 respectively.

Midstream –Liquefaction

· Refer to developments under Upstream above.

Midstream – Refining

· Total refinery throughput for the quarter ended June 30, 2013 was 29,501 barrels per operating day, compared with 23,900 barrels per operating day during the quarter ended June 30, 2012.

· Capacity utilization of the refinery for the quarter ended June 30, 2013, based on 36,500 barrels per day operating capacity, was 72% compared with 60% for quarter ended June 30, 2012. During the quarters ended June 30, 2013 and 2012, our refinery was shut down for 8 day and 9 days, respectively, for general maintenance activities.

Management Discussion and Analysis   INTEROIL CORPORATION   5

· The CRU, which allows the refinery to produce reformate for gasoline has been in operation during the quarter ended June 30, 2013, and has been producing gasoline to supply the domestic market.

· Subsequent to quarter end, 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 will be 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. In addition, BNP Paribas will also be providing an $80.0 million bilateral non-recourse discounting facility. The facility will be 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 plus 3.75% per annum. The facility is subject to Bank of Papua New Guinea approval on the granting of Papua New Guinea security over refinery assets, and other standard closing conditions.

Downstream

· The Papua New Guinea economy has continued to slow in the second quarter of 2013 with the construction phase of the ExxonMobil led PNG LNG project nearing completion. This slowdown has had an effect on the rest of the economy and in particular the construction, shipping and road transport industries. In addition, minerals and agricultural commodity prices have fallen globally and this has negatively impacted the rural and island regions and the mining sector. Total sales volumes for the second quarter ended June 30, 2013 were 179.2 million liters (June 2012 – 188.3 million liters), a decrease of 9.1 million liters, or 4.8% over the same period in 2012.

· Our retail business accounted for approximately 16% of our total downstream sales in the second quarter of 2013 (June 2012 – 15%). We continue to invest in new forecourt technology and in new retail fuel distribution systems. During the quarter, we acquired a key high volume independently owned retail site.

Corporate

· On April 23, 2013, we announced the retirement of Phil Mulacek as Chief Executive Officer, effective April 30, 2013. Mr. Mulacek will continue as a director and will provide advisory services to us.

· On May 29, 2013, we announced the nomination Sir Wilson Kamit CBE for election to the Board. Sir Wilson recently retired as Governor of the Bank of Papua New Guinea and Chairman of its Bank Board. Sir Wilson was elected to the Board of Directors by the shareholders at the Annual Meeting on June 24, 2013.

· On June 24, 2013, Isikeli (“Keli”) Taureka joined us as Executive Vice President of Corporate Development and Government Relations. Keli Taureka was most recently the head of Chevron Corporation’s Geothermal and Power Operations (GPO). Prior to his assignment with GPO, Mr. Taureka was the President of ChevronTexaco China Energy Company with responsibility for Chevron’s oil and gas upstream activities in China. Earlier at Chevron, Mr. Taureka served in a variety of executive positions, including General Manager/Country Manager for Chevron New Guinea Limited, where he was responsible for oil operations in Papua New Guinea and Western Australia.

· Executive Vice President Christian Vinson, who has led our corporate development and Papua New Guinea government relations efforts since our inception, retired in June 2013.

· On July 11, 2013, we announced that Dr. Michael Hession joined us as 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 Six Months Ended June 30, 2013 and 2012

Consolidated – Operating results	Quarter ended June 30,						Six months ended June 30,
($ thousands, except per share data)	2013			2012			2013			2012
				(revised) (4)						(revised) (4)
Sales and operating revenues		344,075			296,908			693,398			632,226
Interest revenue		37			28			52			203
Other non-allocated revenue		1,549			2,167			2,541			4,825
Total revenue		345,661			299,103			695,991			637,254
Cost of sales and operating expenses		(320,300	)		(315,292	)		(635,059	)		(616,628	)
Office and administration and other expenses		(16,684	)		(12,776	)		(27,968	)		(24,381	)
Derivative (losses)/gains		(351	)		632			(822	)		214
Exploration costs		(522	)		(5,240	)		(971	)		(12,604	)
Gain on conveyance of oil and gas properties		-			-			500			-
Loss on Flex LNG Investment		(687	)		-			(1,027	)		-
Foreign exchange (losses)/gains		(7,547	)		(2,632	)		(13,023	)		7,488
Share of net loss of joint venture partnership accounted for using the equity method (4)		(217	)		(295	)		(313	)		(306	)
EBITDA (1)		(647	)		(36,500	)		17,308			(8,963	)
Depreciation and amortization		(5,804	)		(3,915	)		(11,501	)		(10,007	)
Interest expense		(4,511	)		(3,507	)		(8,845	)		(6,942	)
Loss before income taxes		(10,962	)		(43,922	)		(3,038	)		(25,912	)
Income tax (expense)/benefit		(2,268	)		12,209			(6,189	)		3,635
Net loss		(13,230	)		(31,713	)		(9,227	)		(22,277	)
Net loss per share (basic)		(0.27	)		(0.66	)		(0.19	)		(0.46	)
Net loss per share (diluted)		(0.27	)		(0.66	)		(0.19	)		(0.46	)
Total assets		1,308,070			1,155,724			1,308,070			1,155,724
Total liabilities		539,949			409,827			539,949			409,827
Total long-term liabilities		260,235			140,472			260,235			140,472
Gross margin (2)		23,775			(18,384	)		58,339			15,598
Cash flows used in operating activities (3)		(57,224	)		(24,271	)		(16,641	)		(52,762	)

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.

Analysis of Financial Condition Comparing Quarters and Six Months Ended June 30, 2013 and 2012

During the six months ended June 30, 2013, our debt-to-capital ratio (being debt divided by [shareholders’ equity plus debt]) was 18% (13% as at June 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.

Management Discussion and Analysis   INTEROIL CORPORATION   7

Our current ratio (being current assets divided by current liabilities), which measures our ability to meet short-term obligations, was 1.5 times as at June 30, 2013 (1.5 times as at June 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 0.9 times as at June 30, 2013 (0.7 times as at June 30, 2012). The quick ratio was below our internal target of above 1.0 times as at June 30, 2013. The execution of the sales and purchase agreement for the development of PRL 15 resource is expected to bring these ratios within our internal targets.

As at June 30, 2013, our total assets amounted to $1,308.1 million, compared with $1,155.7 million as at June 30, 2012. This increase of $152.4 million, or 13%, from June 30, 2012 was primarily due to expenditure of $87.2 million 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; a $36.6 million net increase in cash and cash equivalents and restricted cash primarily due to receipt of PRE’s $96.0 million initial staged cash payment, partially offset by expenditure on the development of oil and gas properties during the period; a $29.7 million increase in non-current receivables was attributable to the credits given to PacLNG and other indirect participating interest holders on account of their participation in the sell down of interest as part of the farm-in transaction with PRE; an increase in our trade and other receivables balance of $20.2 million on higher refinery export receivables due to timing of shipments and higher joint venture billings to upstream partners; and a $9.9 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 a $33.1 million reduction in inventories balances due to the timing of shipments.

As at June 30, 2013, our total liabilities amounted to $540.0 million, compared with $409.8 million at June 30, 2012. The increase of $130.2 million, or 32%, from June 30, 2012 was primarily due to the 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; a net increase of $55.1 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), partially reduced by the OPIC loan repayment of $35.5 million during the last quarter of 2012 and the ANZ, BSP and BNP syndicated loan repayment of $8.0 million during the second quarter of 2013; and a $59.1 million increase in working capital facilities payable (including trade receivables discounted with recourse). These increases however have been offset by a $63.0 million decrease in accounts payable and accrued liabilities, mainly related to timing of payments on certain crude cargo purchases.

Analysis of Consolidated Financial Results Comparing Quarters and Six Months Ended June 30, 2013 and 2012

Quarterly Comparative

Our net loss for the quarter ended June 30, 2013 was $13.2 million compared with $31.7 million for the same quarter of 2012, a decrease of $18.5 million. The operating segments of Corporate, Midstream - Refining and Downstream collectively derived a net loss for the quarter of $0.5 million (2012 net loss $16.3 million), while the investments in development segments of Upstream and Midstream - Liquefaction resulted in a net loss of $12.7 million (2012 net loss $15.4 million).

The decrease in net loss for the quarter ended June 30, 2013 was mainly due to a $42.2 million increase in gross margin on account of a relatively stable crude and product price movement during the current quarter as compared to a large fall in prices during the same period in 2012; and a $23.8 million net realizable value write down made during the quarter ended June 30, 2012 while there was no inventory write down required during the current quarter. In addition, the $4.7 million decreased exploration costs incurred for seismic activity for PPL 236 has further reduced the net loss. These decreases in net loss have been partly reduced by a $15.5 million decrease in deferred income tax benefits, 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 of the refinery operation using period end rates; a $4.9 million increase in foreign exchange losses, resulting from the weakening of Kina against USD during the quarter ended June 30, 2013 (FX rate decreased from 0.4675 to 0.4570) compared to the same period in 2012 (increased from 0.4820 to 0.4840); and a $3.9 million increase in office and administration expenses, mainly attributable to the retirement expenses incurred for senior management during the current quarter.

Management Discussion and Analysis   INTEROIL CORPORATION   8

Total revenues increased by $46.6 million from $299.1 million in the quarter ended June 30, 2012 to $345.7 million in the quarter ended June 30, 2013, primarily due to higher sales volumes during the quarter. The total volume of all products sold by us was 2.4 million barrels for the quarter ended June 30, 2013, compared with 1.8 million barrels in the same quarter of 2012, mainly contributed by increased refinery exports.

Six Monthly Comparative

Our net loss for the six months ended June 30, 2013 was $9.2 million compared with $22.3 million for the same period of 2012, a decrease of $13.1 million. The operating segments of Corporate, Midstream - Refining and Downstream collectively derived a net profit for the six month period of $18.0 million (2012 net profit $12.4 million), while the investments in development segments of Upstream and Midstream - Liquefaction resulted in a net loss of $27.2 million (2012 net loss $34.7 million).

The decrease in net loss for the six month period ended June 30, 2013 was mainly due to a $42.7 million increase in gross margin on account of a relatively stable crude price movement during the current period ended June 30, 2013 as compared to a large price fall in the same period in 2012; a $23.8 million net realizable value write down made during the period ended June 30, 2012 while there was no inventory write down required during the current period; higher premium from Naphtha sales; and decrease in standard cost per barrel throughput due to increased number of operating days. In addition, the $11.6 million decreased exploration costs incurred for seismic activity for PPL 236 has further reduced the net loss. These decreases in net loss however have been partly offset by a $20.5 million increase in foreign exchange losses, resulting from the weakening of Kina against USD during the six months ended June 30, 2013 (FX rate decreased from 0.4755 to 0.4570) compared to the same period in 2012 (increased from 0.4665 to 0.4840); a $13.3 decrease in deferred tax benefit, 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; a $2.6 million increase in administrative and general expenses, attributable to the retirement expenses incurred during the current period for senior management; and a $2.3 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.

Total revenues increased by $58.7 million from $637.3 million in the six months ended June 30, 2012 to $696.0 million in the six months ended June 30, 2013, primarily due to higher sales volumes during the period. The total volume of all products sold by us was 4.7 million barrels for the six months ended June 30, 2013, compared with 4.0 million barrels in the same period in 2012.

The Upstream segment realized a net loss of $45.8 million in the six months ended June 30, 2013 (2012 net loss $32.8 million). The increase in net loss for the six months ended June 30, 2013 by $13.0 million from the same period of 2012 was mainly due to a $21.9 million increase resulting from the transfer of historical LNG development costs incurred from the Midstream - Liquefaction segment; and a $4.1 million increase in interest charges on the inter-company loan balances provided to fund exploration and development activities. These increases however have been partially reduced by a $11.6 million decrease in exploration costs incurred for seismic activity on PPL 236.

The Midstream - Refining segment generated a net profit of $1.2 million in the six months ended June 30, 2013 (2012 net loss $21.6 million). The decrease in net loss was primarily due a $48.4 million increase in gross margin on account of a relatively stable crude price movement during the current period ended June 30, 2013 as compared to a large price fall in the same period in 2012; a $23.8 million net realizable value write down made during the six months ended June 30, 2012 while there was no inventory write down required during the current period; higher premium from Naphtha sales; and decrease in standard cost per barrel throughput due to increased number of operating days. The increases in gross margin have been partly reduced by a $14.0 million decrease in deferred income tax benefit, mainly 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 of the refinery operation using period end rates. The weakening of Kina against USD during the six months ended June 30, 2013 (FX rate decreased from 0.4755 to 0.4570) compared to the same period in 2012 (increased from 0.4665 to 0.4840) has further lessened the decreases in net loss by $11.1 million.

Management Discussion and Analysis   INTEROIL CORPORATION   9

The Midstream - Liquefaction segment had a net profit of $18.6 million during the six months ended June 30, 2013 (2012 net loss $1.9 million). The increase in net profit from 2012 was mainly due to the transfer of historical LNG development costs incurred in the Midstream - Liquefaction segment to the Upstream segment, being the license holder of oil and gas assets in PRL 15.

The Downstream segment generated a net profit of $10.4 million in the six months ended June 30, 2013 (2012 net profit $19.2 million). The decreased profit was mainly due to a $9.3 million decrease in foreign exchange gains, resulting from the 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 six months ended June 30, 2012, and a $6.7 million decrease in gross margin, on account of the impact of slowing Papua New Guinea economy and a resultant decline in sales volumes, particularly the high margin Jet A1 volumes. These decreases have been partially offset by a $4.5 million decrease in income tax expense, which is in line with the lower profit before income tax earned; and a $1.5 million decrease in interest expense due to lower utilization of the working capital facility during the current period.

The Corporate segment generated a net profit of $5.6 million (2012 net profit $14.7 million). The decrease in profit was mainly due to the expense incurred for the retirement of senior management, a $1.0 million increase in loss from the valuation of FLEX LNG shares and a $0.8 million increase in foreign exchange losses due primarily to the weakening of AUD against USD during the current period.

Variance Analysis

A complete discussion of each of our business segments’ results can be found under the section “Quarter 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 six months ended June 30, 2013 and 2012.

Quarterly Variance ($ millions)	Six Month Variance ($ millions)
$18.5	$13.0	Net loss variance for the comparative periods primarily due to:
Ø $42.2	$42.7	Increase in gross margin for the periods was mainly due to the following contributing factors: + A relatively stable crude and product prices movement during the current six months ended June 30, 2013 as compared to a large fall in prices during the same period in 2012 + A $23.8 million net realizable value write down made during the six months ended June 30, 2012 while there was no inventory write down required during the current period +  higher Naphtha sales with overall better crack spreads and premiums + decrease in standard costs per barrel throughput due to an increased number of operating days and barrels processed and a decreasing cost base.
Ø ($0.6)	($2.3)	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 development works.
Ø ($3.9)	($3.6)	Higher office and administration and other expenses was primarily attributable to the non-recurring expenses incurred for the retirement of senior management.

Management Discussion and Analysis   INTEROIL CORPORATION   10

Ø ($1.0)	($1.0)	Increase in derivative losses was mainly due to the losses incurred for the settlement of commodity contracts during the periods.
Ø $4.7	$11.6	Lower exploration costs incurred for seismic activity for PPL 236 during both periods. The seismic costs were in relation to the Kwalaha and Tuna seismic acquisition programs.
Ø ($0.7)	($1.0)	Increase in loss on available-for-sale investment in both periods was due to the impairment losses recognized for the reduction in fair value of FLEX LNG investment.
Ø ($4.9)	($20.5)	Increase in foreign exchange losses for the six months ended June 30, 2013 was mainly due to the weakening of Kina against USD during the six months ended June 30, 2013 (FX rate decreased from 0.4755 to 0.4570) compared to the same period in 2012 (increased from 0.4665 to 0.4840). Increase in foreign exchange losses for the quarter ended June 30, 2013 was mainly due to the weakening of Kina against USD during the quarter ended June 30, 2013 (FX rate decreased from 0.4675 to 0.4570) compared to the same period in 2012 (increased from 0.4820 to 0.4840).
Ø ($1.9)	($1.5)	Increase in depreciation expense was mainly due to the depreciation for the capital additions which has been acquired over the last year and current period.
Ø ($1.0)	($1.9)	Increase in interest expense was mainly due to the interest expense incurred for the drawdown of $100.0 million under the ANZ, BSP and BNP syndicated loan during the second quarter of 2012.
Ø ($14.5)	($9.8)	Decrease in income tax benefits mainly relates 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 of the refinery operation using period end rates.

Analysis of Consolidated Cash Flows Comparing Quarters and Six Months Ended June 30, 2013 and 2012

As at June 30, 2013, we had cash, cash equivalents, and restricted cash of $97.5 million (June 30, 2012 – $60.9 million), of which $32.7 million (June 30, 2012 - $40.5 million) was restricted. Of the total restricted cash of $32.7 million, $21.1 million (June 30, 2012 - $34.5 million) was restricted pursuant to the BNP working capital facility utilization requirements, $11.2 million (June 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 June 30, 2013, and OPIC facility as at June 30, 2012), and the balance was made up of a cash deposit on office premises together with term deposits on our PPLs.

Cash flows used in operations

Our cash outflows used in operations for the quarter ended June 30, 2013 were $57.2 million compared with $24.3 million for the quarter ended June 30, 2012, a net increase in cash outflows of $32.9 million. This increase in cash outflows was mainly due to a $46.7 million net increase in working capital outflows associated with trade and other receivables, inventories and accounts payables and partly offset by a $13.8 million increase in net cash inflows 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 quarter ended June 30, 2013.

Management Discussion and Analysis   INTEROIL CORPORATION   11

Our cash outflows used in operations for the six months ended June 30, 2013 were $16.6 million compared with $52.7 million for the six months ended June 30, 2012, a net decrease in cash outflows of $36.1 million. This decrease in cash outflows was mainly due to a $24.9 million net decrease in working capital outflows associated with trade and other receivables, inventories and accounts payables and a $11.2 million increase in net cash inflow used in 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 six months ended June 30, 2013.

Cash flows used in investing activities

Cash outflows for investing activities for the quarter ended June 30, 2013 were $27.7 million compared with $46.3 million for the quarter ended June 30, 2012. These outflows mainly relate to the net cash expenditures on exploration, appraisal and development activities (net of IPI cash calls) of $15.7 million, expenditures on plant and equipment of $7.8 million and a $10.4 million decrease in working capital requirements of development segments relating to the timing of payments. These outflows were partially offset by a $6.2 million decrease in restricted cash held as security under the BNP working capital facility.

Cash outflows for investing activities for the six months ended June 30, 2013 were $63.4 million compared with $79.2 million for the six months ended June 30, 2012. These outflows mainly relate to the net cash expenditures on exploration, appraisal and development activities (net of IPI cash calls) of $51.9 million, expenditures on plant and equipment of $11.6 million and a $16.2 million decrease in working capital requirements of development segments relating to the timing of payments. These outflows were partially offset by a $16.3 million decrease in restricted cash held as security under the BNP working capital facility.

Cash flows from financing activities

Cash inflows from financing activities for the quarter ended June 30, 2013 amounted to $81.3 million, compared with inflows of $51.1 million for the quarter ended June 30, 2012. These cash inflows are primarily due to $87.7 million net proceeds from working capital facility and a total of $4.0 million proceeds from the issuance of common shares during the quarter following the exercise of stock options. These cash inflows however were partly offset by an $8.0 million repayment of ANZ, BNP and BSP semi-annual syndicated loan principal installment in May 2013 and a $2.4 million commission paid to PacLNG for facilitating the farm-in transaction between PRE and InterOil.

Cash inflows from financing activities for the six months ended June 30, 2013 amounted to $95.2 million, compared with inflows of $82.8 million for the six months ended June 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 (net of $2.4 million commission paid to PacLNG for facilitating the farm-in-agreement between PRE and InterOil), $27.7 million net proceeds from working capital facility; and a total of $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 an $8.0 million semi-annual principal loan repayment under the ANZ, BNP and BSP syndicated loan facility; and a $2.1 million semi-annual principal loan repayment under the Westpac 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 June 30, 2013 by business segment, and on a consolidated basis.

Quarters ended
($ thousands except per share	2013						2012												2011
data)	Jun-30			Mar-31			Dec-31			Sep-30			Jun-30			Mar-31			Dec-31			Sep-30
Upstream		2,533			1,862			4,136			2,216			1,727			2,284			1,891			2,645
Midstream – Refining		289,300			305,172			301,925			274,671			236,006			302,310			237,640			231,455
Midstream – Liquefaction		20,089			-			-			-			-			-			-			-
Downstream		199,470			208,046			220,512			201,749			223,620			218,974			209,678			186,304
Corporate		36,201			34,923			37,552			26,880			24,742			24,757			21,831			25,078
Consolidation entries		(201,932	)		(199,672	)		(207,686	)		(178,652	)		(186,991	)		(210,174	)		(181,428	)		(163,584	)
Total revenues		345,661			350,331			356,439			326,864			299,104			338,151			289,612			281,898
Upstream		(19,478	)		(1,311	)		(873	)		956			(5,730	)		(6,374	)		665			(6,169	)
Midstream – Refining		840			12,701			12,370			13,417			(42,647	)		18,933			2,604			3,461
Midstream – Liquefaction		19,850			(123	)		192			11			672			(1,410	)		(4,129	)		(3,608	)
Downstream		7,542			10,062			12,258			9,275			11,102			21,414			6,808			3,570
Corporate		1,745			10,044			14,133			9,841			9,975			9,188			10,134			1,548
Consolidation entries		(11,146	)		(13,418	)		(12,199	)		(14,503	)		(9,871	)		(14,216	)		(11,280	)		(10,263	)
EBITDA (1)		(647	)		17,955			25,881			18,997			(36,499	)		27,535			4,802			(11,461	)
Upstream		(32,046	)		(13,774	)		(13,081	)		(10,936	)		(15,532	)		(17,244	)		(9,402	)		(15,080	)
Midstream – Refining		(4,675	)		5,855			13,401			5,358			(32,969	)		11,320			15,684			(1,201	)
Midstream – Liquefaction		19,284			(681	)		(394	)		(573	)		93			(1,969	)		(4,574	)		(3,980	)
Downstream		4,346			6,005			7,716			5,626			6,045			13,195			3,621			1,146
Corporate		(1,701	)		7,342			10,519			7,849			8,445			6,270			7,616			(473	)
Consolidation entries		1,562			(744	)		384			(1,988	)		2,205			(2,136	)		252			(190	)
Net (loss)/profit		(13,230	)		4,003			18,545			5,336			(31,713	)		9,436			13,197			(19,778	)
Net (loss)/profit per share (dollars)
Per Share – Basic		(0.27	)		0.08			0.38			0.11			(0.66	)		0.20			0.27			(0.41	)
Per Share – Diluted		(0.27	)		0.08			0.38			0.11			(0.66	)		0.19			0.27			(0.41	)

(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 SIX MONTH PERIOD IN REVIEW

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

UPSTREAM – QUARTER AND SIX MONTH PERIOD IN REVIEW

Upstream – Operating results	Quarter ended June 30,						Six months ended June 30,
($ thousands)	2013			2012			2013			2012
Other non-allocated revenue		818			1,727			1,410			4,011
Inter-segment revenue - Recharges		1,715			-			2,985			-
Total revenue		2,533			1,727			4,395			4,011
Office and administration and other expenses		(21,585	)		(2,200	)		(24,803	)		(2,872	)
Exploration costs		(522	)		(5,240	)		(971	)		(12,604	)
Gain on conveyance of oil and gas properties		-			-			500			-
Foreign exchange gains/(losses)		96			(17	)		91			(639	)
EBITDA (1)		(19,478	)		(5,730	)		(20,788	)		(12,104	)
Depreciation and amortization		(525	)		715			(1,047	)		(748	)
Interest expense		(12,043	)		(10,517	)		(23,983	)		(19,925	)
Loss before income taxes		(32,046	)		(15,532	)		(45,818	)		(32,777	)
Income tax expense		-			-			-			-
Net loss		(32,046	)		(15,532	)		(45,818	)		(32,777	)

(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 Six Months Ended June 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 six months ended June 30, 2013 and 2012.

Quarterly Variance ($ millions)	Six Month Variance ($ millions)
($16.5)	($13.0)	Net loss variance for the comparative periods primarily due to:
Ø ($0.9)	($2.6)	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 the development works within PRL 15.  Recoveries in relation to our percentage interest of the development projects are offset against the relevant expenses, while the recoveries of the portion relating to external party interests in the development projects are classified under other non-allocated revenue. The reduction in other non-allocated revenue was due to lower activities and related recoveries relating to the construction and drilling related activities during the periods.
Ø $1.7	$3.0	Inter-segment revenue - recharges relates to charges made to other segments for use of construction and logistics services.

Management Discussion and Analysis   INTEROIL CORPORATION   14

Ø ($19.4)	($21.9)	Increase in office and administration expenses was mainly due to the transfer of historical development costs from the Midstream - Liquefaction segment.
Ø $4.7	$11.6	Reduction in exploration costs incurred for seismic activity for PPL 236 during the 2012 periods. The 2012 seismic costs were in relation to the Kwalaha and Tuna seismic acquisition programs.
Ø ($1.5)	($4.1)	Higher interest expense due to an increase in inter-company loan balances provided to fund exploration and development activities.

MIDSTREAM - REFINING – QUARTER AND SIX MONTH PERIOD IN REVIEW

Midstream Refining – Operating results	Quarter ended June 30,						Six months ended June 30,
($ thousands)	2013			2012			2013			2012
External sales		145,333			73,746			287,030			190,439
Inter-segment revenue - Sales		143,965			156,554			307,438			335,389
Inter-segment revenue - Recharges		-			5,692			-			12,314
Interest and other revenue		2			14			5			175
Total segment revenue		289,300			236,006			594,473			538,317
Cost of sales and operating expenses		(279,413	)		(267,023	)		(564,714	)		(544,498	)
Office and administration and other expenses		(2,259	)		(9,612	)		(3,855	)		(17,042	)
Derivative (gains)/losses		(160	)		529			(631	)		99
Foreign exchange losses		(6,628	)		(2,547	)		(11,730	)		(590	)
EBITDA (1)		840			(42,647	)		13,543			(23,714	)
Depreciation and amortization		(3,162	)		(2,891	)		(6,285	)		(5,785	)
Interest expense		(2,235	)		(2,011	)		(4,689	)		(4,781	)
(Loss)/profit before income taxes		(4,557	)		(47,549	)		2,569			(34,280	)
Income tax (expense)/benefit		(118	)		14,580			(1,389	)		12,633
Net (loss)/profit		(4,675	)		(32,969	)		1,180			(21,647	)
Gross Margin (2)		9,885			(36,723	)		29,754			(18,670	)

(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 June 30,						Six Months ended June 30,
Key Refining Metric	2013			2012			2013			2012
Throughput (barrels per day)(1)		29,501			23,900			28,479			23,832
Capacity utilization (based on 36,500 barrels per day operating capacity)		72	%		60	%		73	%		57	%
Cost of production per barrel	$	3.76		$	5.11		$	3.32		$	4.52
Working capital financing cost per barrel of production	$	0.57		$	0.68		$	0.46		$	0.73
Distillates as percentage of production		45	%		62	%		49	%		59	%

(1) Throughput per day has been calculated excluding shut down days. During quarters ended June 30, 2013 and 2012, the refinery was shut down for 8 day and 9 days, respectively.

Analysis of Midstream - Refining Financial Results Comparing the Quarters and Six Months Ended June 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 six months ended June 30, 2013 and 2012.

Quarterly Variance ($ millions)	Six Month Variance ($ millions)
$28.3	$22.8	Net (loss)/ profit variance for the comparative periods primarily due to:
Ø $46.6	$48.4	Increases in gross margin for the periods were mainly due to the following contributing factors: + A relatively stable crude and product prices movement during the current six months ended June 30, 2013 as compared to a large fall in prices during the same period in 2012 + A $23.8 million net realizable value write down made during the six months ended June 30, 2012 while there was no inventory write down required during the current period +  higher Naphtha sales with overall better crack spreads and premiums + decrease in standard costs per barrel throughput due to an increased number of operating days and barrels processed and a decreasing cost base.
Ø ($5.7)	($12.3)	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 six months ended June 30, 2012 were captured within the Midstream - Refining segment and then recharged to other segments.

Management Discussion and Analysis   INTEROIL CORPORATION   16

Ø $7.4	$13.2	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 six months ended June 30, 2012.
Ø ($4.1)	($11.1)	Increase in foreign exchange losses for the six months ended June 30, 2013 was mainly due to the weakening of Kina against USD during the six months ended June 30, 2013 (FX rate decreased from 0.4755 to 0.4570) compared to the same period in 2012 (increased from 0.4665 to 0.4840). Increase in foreign exchange losses for the quarter ended June 30, 2013 was mainly due to the weakening of Kina against USD during the quarter ended June 30, 2013 (FX rate decreased from 0.4675 to 0.4570) compared to the same period in 2012 (increased from 0.4820 to 0.4840).
Ø ($14.7)	($14.0)	Decrease in income tax benefits mainly relates 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 of the refinery operation using period end rates.

MIDSTREAM - LIQUEFACTION – QUARTER AND SIX MONTH IN REVIEW

Midstream Liquefaction – Operating results	Quarter ended June 30,						Six months ended June 30,
($ thousands)	2013			2012			2013			2012
				(revised) (2)						(revised) (2)
Inter-segment revenue - Recharges		20,089			-			20,089			-
Total segment revenue		20,089			-			20,089			-
Office and administration and other expenses		(22	)		967			(49	)		(432	)
Share of net loss of joint venture partnership accounted for using the equity method		(217	)		(295	)		(313	)		(306	)
EBITDA (1)		19,850			672			19,727			(738	)
Interest expense		(566	)		(579	)		(1,124	)		(1,138	)
Profit/(loss) before income taxes		19,284			93			18,603			(1,876	)
Income tax expense		-			-			-			-
Net profit/(loss)		19,284			93			18,603			(1,876	)

(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 Six Months Ended June 30, 2013 and 2012

This segment’s results include our interest in the joint venture development of the proposed midstream facilities of the LNG Project. The development of these facilities is being progressed by way of joint venture with PacLNG through PNG LNG. We currently have an economic interest of 84.582% in PNG LNG.

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.

Management Discussion and Analysis   INTEROIL CORPORATION   17

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

Quarterly Variance ($ millions)	Six Month Variance ($ millions)
$19.2	$20.5	Net profit/(loss) variance for the comparative periods primarily due to:
Ø $20.1	$20.1	Increase in inter-segment revenue - recharges 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 ($1.0)	$0.4	Increase in office, administration and other expense for the quarter was mainly due to the reallocation of certain corporate recharges to the Upstream segment in the second quarter of 2012.

DOWNSTREAM – QUARTER AND SIX MONTH IN REVIEW

Downstream – Operating results	Quarter ended June 30,						Six months ended June 30,
($ thousands)	2013			2012			2013			2012
External sales		198,648			223,137			406,207			441,718
Inter-segment revenue - Sales		70			39			155			57
Interest and other revenue		752			444			1,154			819
Total segment revenue		199,470			223,620			407,516			442,594
Cost of sales and operating expenses		(187,297	)		(208,053	)		(380,687	)		(409,382	)
Office and administration and other expenses		(4,148	)		(4,387	)		(8,529	)		(9,278	)
Foreign exchange (losses)/gains		(483	)		(78	)		(696	)		8,584
EBITDA (1)		7,542			11,102			17,604			32,518
Depreciation and amortization		(1,266	)		(1,241	)		(2,447	)		(2,481	)
Interest expense		(263	)		(909	)		(684	)		(2,141	)
Profit before income taxes		6,013			8,952			14,473			27,896
Income tax expense		(1,667	)		(2,907	)		(4,122	)		(8,652	)
Net profit		4,346			6,045			10,351			19,244
Gross Margin (2)		11,421			15,123			25,675			32,393

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

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

Management Discussion and Analysis   INTEROIL CORPORATION   18

Downstream Operating Review

	Quarter ended June 30,				Six Months ended June 30,
Key Downstream Metrics	2013		2012		2013		2012
Sales volumes (millions of liters)		179.2		188.3		362.9		377.2
Average sales price per liter	$	1.10	$	1.18	$	1.10	$	1.17

Analysis of Downstream Financial Results Comparing the Quarters and Six Months Ended June 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 six months ended June 30, 2013 and 2012.

Quarterly Variance ($ millions)	Six Month Variance ($ millions)
($1.7)	($8.9)	Net profit variance for the comparative periods primarily due to:
Ø ($3.7)	($6.7)	Gross margins decreased compared to the prior year periods mainly due to the decrease in gross margin, on account of the impact of slowing Papua New Guinea economy and a resultant decline in sales volumes, particularly the high margin Jet A1 volumes.
Ø ($0.4)	($9.3)	Increase in foreign exchange loss for the six month period mainly resulted from the weakening of Kina against USD during the six months ended June 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 six months ended June 30, 2012.
Ø $0.6	$1.5	Decrease in interest expense was mainly due to lower utilization of the working capital facility during the periods.
Ø $1.2	$4.5	Decrease in income tax expense mainly due to the lower profit before tax earned during the periods.

Management Discussion and Analysis   INTEROIL CORPORATION   19

CORPORATE – QUARTER AND SIX MONTH IN REVIEW

Corporate – Operating results	Quarter ended June 30,						Six months ended June 30,
($ thousands)	2013			2012			2013			2012
External sales		93			24			162			70
Inter-segment revenue - Sales		6,265			5,339			13,157			10,034
Inter-segment revenue - Recharges		17,154			7,324			32,464			15,286
Interest revenue		12,689			12,055			25,341			24,109
Total revenue		36,201			24,742			71,124			49,499
Cost of sales and operating expenses		(5,347	)		(4,639	)		(11,004	)		(8,530	)
Office and administration and other expenses		(27,698	)		(10,240	)		(46,424	)		(22,052	)
Derivative (losses)/gains		(191	)		103			(191	)		115
Foreign exchange (losses)/gains		(533	)		9			(689	)		132
Loss on Flex LNG investment		(687	)		-			(1,027	)		-
EBITDA (1)		1,745			9,975			11,789			19,164
Depreciation and amortization		(882	)		(530	)		(1,788	)		(1,058	)
Interest expense		(2,081	)		(1,535	)		(3,681	)		(3,044	)
(Loss)/profit before income taxes		(1,218	)		7,910			6,320			15,062
Income tax (expense)/benefit		(483	)		535			(678	)		(345	)
Net (loss)/profit		(1,701	)		8,445			5,642			14,717
Gross Margin (2)		1,011			724			2,315			1,574

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

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

Analysis of Corporate Financial Results Comparing the Quarters and Six Months Ended June 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 six months ended June 30, 2013 and 2012.

Quarterly Variance ($ millions)	Six Month Variance ($ millions)
($10.1)	($9.1)	Net (loss)/profit variance for the comparative periods primarily due to:
Ø $9.8	$17.2	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 $0.6	$1.2	Higher interest income due to an increase in inter-company loan balances.

Management Discussion and Analysis   INTEROIL CORPORATION   20

Ø ($17.5)	($24.4)	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 six months ended June 30, 2012.  In addition, there were non-recurring expenses incurred for the retirement of senior management during the quarter ended June 30, 2013.
Ø ($0.5)	($0.8)	Increase in exchange losses was primarily attributable to the revaluation loss incurred for the receivables denominated in AUD. The AUD has been weakening against USD for both periods (FX rate has decreased from 1.0383 on January 1, 2013 to 0.9133 on June 30, 2013 and FX rate has decreased from 1.0416 on April 1, 2013 to 0.9133 on June 30, 2013).
Ø ($0.7)	($1.0)	Increase in loss on available-for-sale investment in both periods was due to the impairment losses recognized for the reduction in fair value of FLEX LNG investment as of the period ends.
Ø ($1.0)	($0.3)	Increase in income tax expense for the quarter was primarily due to the income tax provision for Papua New Guinea corporate office, which began operations in October 2012.

CONSOLIDATION ADJUSTMENTS – QUARTER AND SIX MONTH IN REVIEW

Consolidation adjustments – Operating results	Quarter ended June 30,						Six months ended June 30,
($ thousands)	2013			2012			2013			2012
Inter-segment revenue - Sales		(150,299	)		(161,931	)		(320,751	)		(345,481	)
Inter-segment revenue - Recharges		(38,958	)		(13,016	)		(55,537	)		(27,598	)
Interest revenue (1)		(12,675	)		(12,045	)		(25,318	)		(24,088	)
Total revenue		(201,932	)		(186,992	)		(401,606	)		(397,167	)
Cost of sales and operating expenses (2)		151,757			164,423			321,346			345,782
Office and administration and other expenses (3)		39,029			12,697			55,693			27,296
EBITDA (4)		(11,146	)		(9,872	)		(24,567	)		(24,089	)
Depreciation and amortization (5)		31			33			65			64
Interest expense (1)		12,677			12,044			25,317			24,087
Profit before income taxes		1,562			2,205			815			62
Income tax expense		-			-			-			-
Net profit		1,562			2,205			815			62
Gross Margin (6)		1,458			2,492			595			301

(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”.

Management Discussion and Analysis   INTEROIL CORPORATION   21

Analysis of Consolidation Adjustments Comparing the Quarters and Six Months Ended June 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 six months ended June 30, 2013 and 2012.

	Quarterly Variance ($ millions)	Six Month Variance ($ millions)
	($0.6)	$0.8	Net loss variance for the comparative periods primarily due to:
Ø	($0.6)	$0.8	Variance in net loss due to changes in intra-group profit eliminated on consolidation between Midstream Refining and Downstream segments in the prior periods relating to the Midstream Refining segment’s profit component of inventory on hand in the Downstream segment at period ends.

LIQUIDITY AND CAPITAL RESOURCES

Summary of Debt Facilities

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

Organization	Facility		Balance outstanding June 30, 2013			Effective interest rate			Maturity date
ANZ, BSP and BNP syndicated secured loan facility	$	100,000,000	$	92,000,000			6.89	%	November 2017
BNP working capital facility	$	240,000,000	$	117,295,332	(1)		2.53	%	See detail below
Westpac PGK working capital facility	$	41,130,000	$	4,733,334			9.50	%	November 2014
BSP PGK working capital facility	$	22,850,000		-			9.45	%	August 2013
Westpac secured loan	$	10,714,000	$	10,714,000			4.58	%	September 2015
2.75% convertible notes	$	70,000,000	$	69,998,000			7.91	%(3)	November 2015
Mitsui unsecured loan (2)	$	11,912,297	$	11,912,297			6.88	%	See detail below

^{(1) There were no letters of credit outstanding at June 30, 2013 and therefore the available borrowings under the facility were $122.7 million at June 30, 2013.}

^{(2) Facility is to fund our share of the Condensate Stripping Project costs as they are incurred pursuant to the CSP JVOA with Mitsui. This Facility was terminated subsequent to June 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.}

Management Discussion and Analysis   INTEROIL CORPORATION   22

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, planned development of the LNG Project and Condensate Stripping Project 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.

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 June 30, 2013 was $92.0 million. The interest rate on the loan is equal to LIBOR plus 6.5%. During the six months ended June 30, 2013, the weighted average interest rate under the facility was 6.89%.

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 six months ended June 30, 2013, a loan installment payment of $8.0 million was paid. As at June 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 June 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)

This working capital facility is used to finance purchases of crude feedstock for our refinery. In accordance with the agreement with BNP, the total facility is split into two components, Facility 1 and Facility 2. In October 2012, the working capital facility agreement with a maximum availability of $240.0 million was amended so that the facility was made evergreen and the annual renewal requirement removed. As at June 30, 2013, Facility 1 has a sublimit of $180.0 million and finances the purchases of crude and hydrocarbon products through the issuance of documentary letters of credit and standby letters of credit, short term advances, advances on merchandise and freight loans, and has a sublimit of Euro 18.0 million or the USD equivalent for hedging transactions. Facility 2 allows borrowings of up to $60.0 million and can be used for partly cash-secured short term advances and for discounting of any monetary receivables acceptable to BNP in order to reduce Facility 1 balances. The facility is secured by sales contracts, purchase contracts, certain cash accounts associated with the refinery, all crude and refined products of the refinery and trade receivables.

As of June 30, 2013, $122.7 million remained available for use under the 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 2.53% for the six months ended June 30, 2013 (compared with 3.19% for the same period of 2012), after including the reduction in interest due to the deposit amounts (restricted cash) maintained as security.

Subsequent to quarter end, 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 will be 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. In addition, BNP Paribas will also be providing an $80.0 million bilateral non-recourse discounting facility. The facility will be secured by our right, 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 subject to Bank of Papua New Guinea approval on the granting of Papua New Guinea security over refinery assets, and other standard closing conditions.

Management Discussion and Analysis   INTEROIL CORPORATION   23

Bank South Pacific and Westpac Working Capital Facility (Downstream)

On October 24, 2008, we secured a combined revolving working capital facility for our Downstream wholesale and retail petroleum products distribution business from BSP and Westpac. The facility limit as at June 30, 2013 was PGK 140.0 million (approximately $64.0 million).

The Westpac facility limit is PGK 90.0 million (approximately $41.1 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 $4.6 million). The BSP facility limit is PGK 50.0 million (approximately $22.9 million), and was renewed in November 2012 for another year ending in August 2013. As at June 30, 2013, PGK 10.4 million (approximately $4.7 million) of this combined facility has been utilized, and PGK 129.6 million (approximately $59.3 million) of this facility remains available for use.

The weighted average interest rate under the Westpac facility was 9.50% for the six months ended June 31, 2013, and the weighted average interest rate under the BSP facility was 9.45% for the six months ended June 30, 2013.

Westpac Secured Loan (Downstream)

In 2012, we obtained a secured loan of $15.0 million from Westpac which is repayable in equal installments over 3.5 years with an interest rate of LIBOR plus 4.4% per annum. The loan agreement stipulates semi-annual principal payments of $2.1 million, with the final repayment to be made in August 2015. The loan is secured by a fixed and floating charge over the assets of Downstream operations. The balance outstanding under the loan as at June 30, 2013 was $10.7 million.

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 quarter ended June 30, 2013, $2,000 of the convertible notes were converted into cash.

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 hold equal interest in the joint venture. Mitsui is to be responsible for arranging or providing financing for the capital costs of the condensate stripping facility.

Management Discussion and Analysis   INTEROIL CORPORATION   24

The portion of funding that relates to Mitsui’s share of the Condensate Stripping Project as at June 30, 2013, amounting to approximately $13.5 million, is held in current liabilities as the agreement requires refund of all funds advanced by Mitsui under the preliminary financing agreement if a positive FID was not reached. The portion of funding that relates to our share of the Condensate Stripping Project (amounting to $11.9 million), funded by Mitsui, is classed as an unsecured loan and interest accrues daily based on LIBOR plus a margin of 6%. During the six months ended June 30, 2013, the weighted average interest rate was 6.88%.

Subsequent to quarter end, 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 are required to make certain payments to Mitsui. On July 3, 2013, we paid Mitsui $6.3 million in relation to the call option, and $9.5 million on July 31, 2013 being the first of three equal installments in relation to Mitsui’s share of capital expenditure incurred and the repayment of the unsecured loan, together with interest thereon. The remaining two installments will be paid on August 31, 2013 and September 30, 2013 respectively, at which time we will have fully repaid this facility.

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 June 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 June 30,						Six months ended June 30,
($ thousands)	2013			2012			2013			2012
				(revised)						(revised)
Net cash (outflows)/inflows from:
Operations		(57,224	)		(24,271	)		(16,641	)		(52,762	)
Investing		(27,715	)		(46,300	)		(63,417	)		(79,209	)
Financing		81,325			51,058			95,189			82,769
Net cash movement		(3,614	)		(19,513	)		15,131			(49,202	)
Opening cash		68,462			39,877			49,721			68,575
Exchange (losses)/gains on cash and cash equivalents		(6	)		71			(10	)		1,062
Closing cash		64,842			20,435			64,842			20,435

Management Discussion and Analysis   INTEROIL CORPORATION   25

Analysis of Cash Flows Used In Operating Activities Comparing the Quarters and Six Months Ended June 30, 2013 and 2012

The following table outlines the key variances in the cash outflows from operating activities between the quarters and six months ended June 30, 2013 and 2012:

	Quarterly variance ($ millions)	Six Month variance ($ millions)
	($33.0)	$36.1	Variance for the comparative periods primarily due to:
Ø	$13.8	$11.2	Increase in cash generated by operations prior to changes in operating working capital for the quarter and six months ended June 30, 2013, mainly due to the decrease in net profit from operations adjusted for decrease in future income tax benefit, and offset by the decrease in inventory revaluation loss.
Ø	($46.8)	$24.9	Increase in cash employed by operations relating to changes in operating working capital for the quarter. The movement was due primarily to a $145.4 million decrease in accounts payable and accrued liabilities and a $12.1 million increase in trade and other receivables; and offset by a $104.9 million decrease in inventories due to timing of crude and export shipments and a $5.8 million decrease in other current assets and prepaid expenses. Decrease in cash employed by operations relating to changes in operating working capital for the six month period. The movement was due primarily to a $77.8 million decrease in inventories due to timing of crude and export shipments and a $4.5 million decrease in other current assets and prepaid expenses; and partially offset by a $39.6 million increase in trade and other receivables and a $17.8 million decrease in accounts payable and accrued liabilities.

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

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

	Quarterly variance ($ millions)	Six Month variance ($ millions)
	$18.6	$15.8	Variance for the comparative periods primarily due to:
Ø	$16.6	$23.8	Lower cash outflows on exploration and development program expenditures mainly due to a reduction in drilling activities, resulting from the ongoing sell down process.
Ø	$11.7	$11.5	Higher cash calls and related inflows from joint venture partners relating to the Triceratops-2 well and historical infrastructure costs.
Ø	($2.7)	$1.6	Movements in expenditure on plant and equipment were mainly due to movement of expenditure on plant and equipment in Downstream and Midstream-Refinery 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.

Management Discussion and Analysis   INTEROIL CORPORATION   26

Ø   $0.0	($11.8)	Maturity of short term PGK Treasury bills during the six months ended June 30, 2012.
Ø   $5.5	$17.6	Higher cash inflows 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 as at June 30, 2013.
Ø ($12.5)	($26.9)	Movements in non-operating working capital relating to accounts payable and accruals in our Upstream operations.

Analysis of Cash Flows Generated From Financing Activities Comparing the Quarters and Six Months Ended June 30, 2013 and 2012

The following table outlines the key variances in the cash inflows from financing activities between quarters and six months ended June 30, 2013 and 2012:

	Quarterly variance ($ millions)	Six Month variance ($ millions)
	$30.3	$12.4	Variance for the comparative periods primarily due to:
Ø	$4.5	$4.5	Repayment of OPIC loan principal installment during the quarter and six months ended June 30, 2012.
Ø	$0.0	($17.1)	Drawdown of the $15.0 million secured loan from Westpac during the six months ended June 30, 2012. A $2.1 million semi-annual principal loan repayment was subsequently made during the current six month period.
Ø	($22.4)	$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 PPL#237 during the quarter ended June 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	$56.1	($18.7)	Movement in utilization of the BNP Paribas working capital facility is due to movement in working capital requirements.
Ø	($8.0)	($8.0)	Repayment of ANZ, BSP and BNP semi-annual syndicated loan principal installment during the six months ended June 30, 2013.
Ø	$0.1	($1.9)	Movements were due to the receipts of cash from the exercise of stock options during the six months ended June 30, 2013.

Management Discussion and Analysis   INTEROIL CORPORATION   27

Capital Expenditures

Upstream Capital Expenditures

Capital expenditures for our Upstream segment in Papua New Guinea for the quarter ended June 30, 2013 were net credits of $6.3 million, compared with the net outflows of $44.9 million during the same period of 2012. Total net expenditures for the six month period ended June 30, 2013 were $27.9 million compared to $88.5 million during the same period in 2012.

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

	Quarterly ($ millions)	Six Month ($ millions)
	($6.3)	$27.9	Expenditures in the quarter and six months ended June 30, 2013 primarily due to:
Ø	($0.3)	$7.0	Costs incurred for site preparation, pre-spud and drilling works at the  Antelope-3 well site.
Ø	$2.6	$6.2	Costs incurred for Elk-3 well site preparation, spud works, drilling and standby works.
Ø	$0.6	$4.0	Costs incurred for Herd Base to Antelope field road construction and maintenance (South Road).
Ø	$0.2	$1.5	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	$1.2	$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	$2.7	$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.
Ø	$14.3	$25.4	General management costs recharged to the projects, and under recoveries in relation to the drilling services, construction equipment, labor, logistics and warehousing services provided due to reduced activities during the periods.
Ø	($14.1)	($14.1)	Allocation of historical Triceratops-2 well costs to PRE (net of credits given to other joint venture partners).
Ø	($15.2)	($15.2)	Allocation of historical northern infrastructure costs in the Elk and Antelope fields to joint venture partners.
Ø	$1.7	$2.5	Other expenditures, including equipment purchases and drilling inventory.

Midstream – Refining Capital Expenditures

Capital expenditures totaled $3.5 million in our Midstream - Refining segment for the six months ended June 30, 2013, mainly associated with tank, CRU and other minor upgrade works.

Downstream Capital Expenditures

Capital expenditures for the Downstream segment totaled $8.4 million for the six months ended June 30, 2013. These expenditures mainly related to the upgrade projects across various fuel stations, terminals and depots.

Management Discussion and Analysis   INTEROIL CORPORATION   28

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 June 30, 2013, we are committed under the terms of our exploration licenses or PPL’s to spend a further $48.0 million through 2014. As at June 30, 2013, management estimates that satisfying these license commitments with the expenditure of $48.0 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, are complete. We have spent $441.6 million on PRL 15 which includes seismic, Herd Base/Hou Creek wharf and camps, roads, FEED for wells, gas gathering, condensate stripping, and pipelines. $52.8 million of the expenditures to date relates to the $73.0 million commitment. Expenditure on the drilling of further delineation wells, post the completion of ExxonMobil agreement 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. In September 2011, we retained financial advisors to help solicit and evaluate proposals from potential strategic partners to acquire interests in our Elk and Antelope fields, a condensate stripping facility, the LNG Project and exploration licenses. We are currently negotiating with a party which submitted a bid during that process.

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.

On May 24, 2013, we entered into exclusive negotiations with ExxonMobil for the development of our PRL 15 resource. The transaction has been discussed with the Government of Papua New Guinea in general terms and any future agreement will be subject to Papua New Guinea Government approval. Items under consideration in those negotiations include:

– We and PacLNG selling to ExxonMobil an interest in PRL 15 that is sufficient to supply gas to develop an additional LNG train at ExxonMobil’s PNG LNG Project at Konebada. There will be staged payments before and after production commences.

Management Discussion and Analysis   INTEROIL CORPORATION   29

– ExxonMobil will pay our costs of drilling additional delineation wells in the Elk and Antelope fields, which will be followed by certification of the resource. The resource recertification will be used to determine the economic interest of ExxonMobil in the license.

– We will have the optionality to either independently develop a second LNG project in the Gulf Province that may also use gas from PRL 15, and potentially other discoveries, such as Triceratops, or pursue further development with ExxonMobil.

We can give no assurance that we will be successful in completing a transaction with ExxonMobil on terms acceptable to us.

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.

Subsequent to quarter end, 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 will be 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. In addition, BNP Paribas will also be providing an $80.0 million bilateral non-recourse discounting facility. The facility will be secured by our right, 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 subject to Bank of Papua New Guinea approval on the granting of Papua New Guinea security over refinery assets, and other standard closing conditions.

Midstream - Liquefaction

Completion of an LNG Project 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 certain common 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:

Management Discussion and Analysis   INTEROIL CORPORATION   30

	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 (a)		68,200		58,100		10,100		-		-		-		-
Secured and unsecured loans		131,993		44,852		22,982		25,668		26,076		12,415		-
2.75% Convertible notes obligations		74,652		1,925		1,925		70,802		-		-		-
Indirect participation interest - PNGDV		1,384		1,384		-		-		-		-		-
Total		276,229		106,261		35,007		96,470		26,076		12,415		-

(a) 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 $48.0 million as a condition of renewal of our petroleum prospecting licenses through 2014 under our exploration licenses. As at June 30, 2013, management estimates that satisfying this license commitment with the expenditure of $48.0 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 $20.2 million on the development of the Elk and Antelope fields by the end of 2014.

Off Balance Sheet Arrangements

Neither during the six months ended, nor as at June 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 six months ended 30 June, 2013, two of our executive officers retired.  The compensation paid or payable to these officers upon their termination was a total of $8,700,000.

(b) Phil Mulacek consultancy services

Phil Mulacek, a director of InterOil, provided advisory services to us during the six months ended June 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 period amounted to $50,000.

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 June 30, 2013, we had 48,812,742 common shares (50,529,978 common shares on a fully diluted basis) and no preferred shares issued and outstanding. The potential dilutive instruments outstanding as at June 30, 2013 included employee stock options and restricted stock in respect of 985,232 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 August 07, 2013, we had 48,812,742 common shares (50,589,801 common shares on a fully diluted basis) and no preferred shares issued and outstanding. The potential dilutive instruments outstanding as at August 07, 2013 included employee stock options and restricted stock in respect of 1,045,055 common shares and 732,004 common shares relating to the $70.0 million principal amount 2.75% convertible senior notes due November 15, 2015.

Management Discussion and Analysis   INTEROIL CORPORATION   31

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.

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 June 30, 2013, we had a net receivable of $0.2 million (June 30, 2012 – receivable of $0.8 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 June 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 June 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 $369,647,446 temporary differences and carried forward losses in relation to exploration expenditures incurred in Papua New Guinea as at June 30, 2013. No deferred tax assets have been recognized for these exploration expenditures as at June 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.

Management Discussion and Analysis   INTEROIL CORPORATION   32

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.

NEW ACCOUNTING STANDARDS

New accounting standards not yet applicable as at June 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 June 30,						Six months ended June 30,
($ thousands)	2013			2012			2013			2012
Midstream – Refining		289,298			230,300			594,468			525,828
Downstream		198,718			223,176			406,362			441,775
Corporate		6,358			5,363			13,319			10,104
Consolidation Entries		(150,299	)		(161,931	)		(320,751	)		(345,481	)
Sales and operating revenues		344,075			296,908			693,398			632,226
Midstream – Refining		(279,413	)		(267,023	)		(564,714	)		(544,498	)
Downstream		(187,297	)		(208,053	)		(380,687	)		(409,382	)
Corporate (1)		(5,347	)		(4,639	)		(11,004	)		(8,530	)
Consolidation Entries		151,757			164,423			321,346			345,782
Cost of sales and operating expenses		(320,300	)		(315,292	)		(635,059	)		(616,628	)
Midstream – Refining		9,885			(36,723	)		29,754			(18,670	)
Downstream		11,421			15,123			25,675			32,393
Corporate (1)		1,011			724			2,315			1,574
Consolidation Entries		1,458			2,492			595			301
Gross Margin		23,775			(18,384	)		58,339			15,598

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

Management Discussion and Analysis   INTEROIL CORPORATION   33

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.

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

Management Discussion and Analysis   INTEROIL CORPORATION   34

Quarters ended	2013						2012												2011
($ thousands)	Jun-30			Mar-31			Dec-31			Sep-30			Jun-30			Mar-31			Dec-31			Sep-30
Upstream		(19,478	)		(1,311	)		(873	)		956			(5,730	)		(6,374	)		665			(6,169	)
Midstream – Refining		840			12,701			12,370			13,417			(42,647	)		18,933			2,604			3,461
Midstream – Liquefaction		19,850			(123	)		192			11			672			(1,410	)		(4,129	)		(3,608	)
Downstream		7,542			10,062			12,258			9,275			11,102			21,414			6,808			3,570
Corporate		1,745			10,044			14,133			9,841			9,975			9,188			10,134			1,548
Consolidation Entries		(11,146	)		(13,418	)		(12,199	)		(14,503	)		(9,871	)		(14,216	)		(11,280	)		(10,263	)
Earnings before interest, taxes, depreciation and amortization		(647	)		17,955			25,881			18,997			(36,499	)		27,535			4,802			(11,461	)
Subtract:
Upstream		(12,043	)		(11,941	)		(11,734	)		(11,438	)		(10,517	)		(9,408	)		(8,712	)		(7,806	)
Midstream – Refining		(2,235	)		(2,454	)		(11,390	)		(1,654	)		(2,011	)		(2,771	)		(3,285	)		(2,494	)
Midstream – Liquefaction		(566	)		(558	)		(586	)		(584	)		(579	)		(559	)		(445	)		(372	)
Downstream		(263	)		(422	)		(337	)		(394	)		(909	)		(1,233	)		(1,170	)		(1,233	)
Corporate		(2,081	)		(1,600	)		(1,601	)		(1,540	)		(1,535	)		(1,510	)		(1,498	)		(1,477	)
Consolidation Entries		12,677			12,642			12,552			12,482			12,044			12,047			11,500			10,041
Interest expense		(4,511	)		(4,333	)		(13,096	)		(3,128	)		(3,507	)		(3,434	)		(3,610	)		(3,341	)
Upstream		-			-			-			-			-			-			-			-
Midstream – Refining		(118	)		(1,270	)		16,574			(3,484	)		14,580			(1,948	)		19,243			678
Midstream – Liquefaction		-			-			-			-			-			-			-			-
Downstream		(1,667	)		(2,455	)		(3,070	)		(1,791	)		(2,907	)		(5,746	)		(595	)		(297	)
Corporate		(483	)		(196	)		(1,330	)		177			535			(880	)		(493	)		(195	)
Consolidation Entries		-			-			-			-			-			-			-			-
Income taxes		(2,268	)		(3,921	)		12,174			(5,098	)		12,208			(8,574	)		18,155			186
Upstream		(525	)		(522	)		(474	)		(454	)		715			(1,462	)		(1,355	)		(1,105	)
Midstream – Refining		(3,162	)		(3,122	)		(4,153	)		(2,921	)		(2,891	)		(2,894	)		(2,878	)		(2,846	)
Midstream – Liquefaction		-			-			-			-			-			-			-			-
Downstream		(1,266	)		(1,180	)		(1,135	)		(1,464	)		(1,241	)		(1,240	)		(1,422	)		(894	)
Corporate		(882	)		(906	)		(683	)		(629	)		(530	)		(528	)		(527	)		(349	)
Consolidation Entries		31			32			31			33			32			33			32			32
Depreciation and amortisation		(5,804	)		(5,698	)		(6,414	)		(5,435	)		(3,915	)		(6,091	)		(6,150	)		(5,162	)
Upstream		(32,046	)		(13,774	)		(13,081	)		(10,936	)		(15,532	)		(17,244	)		(9,402	)		(15,080	)
Midstream – Refining		(4,675	)		5,855			13,401			5,358			(32,969	)		11,320			15,684			(1,201	)
Midstream – Liquefaction		19,284			(681	)		(394	)		(573	)		93			(1,969	)		(4,574	)		(3,980	)
Downstream		4,346			6,005			7,716			5,626			6,045			13,195			3,621			1,146
Corporate		(1,701	)		7,342			10,519			7,849			8,445			6,270			7,616			(473	)
Consolidation Entries		1,562			(744	)		384			(1,988	)		2,205			(2,136	)		252			(190	)
Net (loss)/profit per segment		(13,230	)		4,003			18,545			5,336			(31,713	)		9,436			13,197			(19,778	)

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 six months ended June 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

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

“Board” means the board of directors of InterOil.

“BSP” means Bank of South Pacific Limited.

“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 six months ended June 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.

“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.

“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.

“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.

Management Discussion and Analysis   INTEROIL CORPORATION   37

“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 of liquefaction facilities in the Gulf Province of Papua New Guinea described as our Midstream Liquefaction business segment and being undertaken as a joint venture with PacLNG and with other potential partners, including the State.

“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.

“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.

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“PacLNG” means Pacific LNG Operations Ltd., a company incorporated under the laws of the Bahamas and affiliated with Clarion Finanz A.G. This company is our joint venture partner in the LNG Project (holding equal voting shares in PNG LNG), holds a 2.5% direct interest in the Elk and Antelope fields, is an IPI holder and a majority shareholder in PNGDV.

“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 to hold the interests of certain joint venturers in the venture to construct the proposed liquefaction facilities. Shareholders are InterOil LNG Holdings Inc., a wholly-owned subsidiary of InterOil, and PacLNG.

“PPL” means Petroleum Prospecting License. The tenement given by the State to explore for oil and gas.

“PRE” means Pacific Rubiales Energy Corp., a company incorporated under the laws of British Columbia, Canada.

“PRL” means Petroleum Retention License, the tenement given by the State to allow the license holder to evaluate the commercial and technical options for the potential development of an oil and/or gas field.

“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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