InterOil Corporation Management Discussion and Analysis   (Amended and Restated)   For the year ended December 31, 2012 March 7, 2013

TABLE OF CONTENTS
FORWARD-LOOKING STATEMENTS	2
OIL AND GAS DISCLOSURES	3
INTRODUCTION	4
BUSINESS STRATEGY	5
OPERATIONAL HIGHLIGHTS	5
SELECTED FINANCIAL INFORMATION AND HIGHLIGHTS	10
QUARTER AND YEAR IN REVIEW	19
LIQUIDITY AND CAPITAL RESOURCES	27
INDUSTRY TRENDS AND KEY EVENTS	37
RISK FACTORS	39
CRITICAL ACCOUNTING ESTIMATES	40
NEW ACCOUNTING STANDARDS	41
NON-GAAP MEASURES AND RECONCILIATION	43
PUBLIC SECURITIES FILINGS	44
DISCLOSURE CONTROLS AND PROCEDURES AND INTERNAL CONTROLS OVER FINANCIAL REPORTING	45
GLOSSARY OF TERMS	45

EXPLANATION NOTE

InterOil Corporation (the "Company") is re-filing its management's discussion and analysis for the year ended December 31, 2012 ("MD&A") to provide a conclusion about the effectiveness of its disclosure controls and procedures and internal control over financial reporting under National Instrument 52-109 Certification of Disclosure in Issuers' Annual and Interim Filings.

The only amendment to the MD&A is set forth under the heading "Disclosure Controls and Procedures and Internal Controls Over Financial Reporting" in the MD&A, which sets forth that (i) that the Chief Executive Officer and Chief Financial Officer have (i) evaluated, or caused to be evaluated under their supervision, the effectiveness of the Company's disclosure controls and procedures at its financial year-end and have concluded that the Company's disclosure controls and procedures are effective at the December 31, 2012; and (ii) evaluated, or caused to be evaluated under their supervision, the effectiveness of the Company's internal controls over financial reporting at its financial year-end and have concluded that the Company's internal controls over financial reporting are effective at the December 31, 2012.

No other changes were made to the MD&A originally filed on February 27, 2013.

This MD&A should be read in conjunction with our audited annual consolidated financial statements and accompanying notes for the year ended December 31, 2012 and our annual information form (the “2012 Annual Information Form”) for the year ended December 31, 2012. The MD&A was prepared by management and provides a review of our performance in the year ended December 31, 2012, 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”) 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 December 31, 2012 and for the quarter and year ended December 31, 2012, unless otherwise specified. A listing of specific defined terms can be found in the “Glossary of Terms” section of this MD&A.

Management Discussion and Analysis   INTEROIL CORPORATION   1

FORWARD-LOOKING STATEMENTS

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

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; the construction of the LNG Project and the Condensate Stripping Project in Papua New Guinea; the development of the LNG Project and the Condensate Stripping Project; the timing and cost of such 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; re-commissioning of our CRU; 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;

· 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 defaults.

· interest rate risk;

· weather conditions and unforeseen operating hazards;

Management Discussion and Analysis   INTEROIL CORPORATION   2

· 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 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 to 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 December 31, 2012.

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 for the proposed delivery of natural gas to the Midstream Liquefaction segment and condensate to the Midstream Refining segment. 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 PNG 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 year, for each of the segments is as follows:

Upstream

· Triceratops field appraisal program:

– On January 15, 2012, we spudded the Triceratops-2 appraisal well in PPL 237 in PNG. The Triceratops-2 well is located approximately 3.5 kilometers west of the Bwata-1 discovery well and 4.7 kilometers southwest from the Triceratops-1 well. The primary objectives of the Triceratops-2 well were to confirm the presence of gas and condensate, test for the presence of reefal carbonate reservoir, and, in the event of success, complete the well as a future production well. We drilled the entire reservoir interval with a total depth of 7,336 feet (2,236 meters) on April 6, 2012 and the acquisition of wireline logs was completed on April 14, 2012.

– On May 14, 2012, we successfully drill stem tested the upper reservoir section in the Triceratops-2 well. The DST #8 was conducted in the open hole interval from 4,111 feet (1,253 meters) to 4,859 feet (1,481 meters) and the well was opened to increasing choke settings before being closed for final buildup. The well flowed natural gas and condensate at a rate of 17.6 Mmscfpd through a 48/64 inch choke with an observed CGR at separator conditions of between 13.6 and 16.3 barrels per million standard cubic feet of gas. The corresponding wellhead pressure was recorded as 1,382 psig. This gas flow rate compared favorably with results from equivalent DST intervals at the Antelope-1 and Antelope-2 wells which were a rate of 12.4 to 18 Mmscfpd and a rate of 11.2 to 17.4 Mmscfpd, respectively.

– The Triceratops-2 well logs and DST pressure data indicated two stratigraphically separate carbonate reservoir intervals with separate pressure systems and potentially separate or stacked hydrocarbon pay. The upper reservoir interval contains gas and condensate which preliminary pressure data (DST #7) indicates is on the same pressure trend as the gas and condensate tested 3.5 kilometers away in the Bwata-1 well. The deeper zone is separated from the upper reservoir interval by a 264 feet (80.5 meters) marl and argillaceous limestone interval from 4,869 feet (1,484 meters) to 5,133 feet (1,564 meters) a potential intraformational seal. DST #2 tested the interval between 6,358 feet (1,938 meters) and 6,454 feet (1,967 meters) in this deeper section and this data indicates a separate pressure system in this interval from the upper reservoir interval.

– Following successful flow from DST #9 of 27 Mmscfpd on June 6, 2012, the Triceratops-2 well was declared a discovery on June 14, 2012 by the DPE.

– Between June 14, 2012 and August 13, 2012, the well was cased and cased hole logging and testing was completed. DST #10 established gas in the lower limestone and production logs established a gas water contact. A number of rotary side wall cores were also taken, and underwent petrophysical analysis, routine core analysis and special core analysis to help determine the hydrocarbon saturation in the reservoir, which is an important input into the resource estimates.

– The DPE granted approval to remove Rig#2 from the Triceratops-2 well on August 13, 2012. The Triceratops-2 well has been suspended as a new discovery for recompletion at a later date as a future production well. Demobilization of the rig began immediately for relocation to the Antelope-3 well.

– Completion of vertical seismic profile processing of the Triceratops field reaffirmed the connection between the well and seismic data, and remapping of this seismic data is ongoing. Triceratops seismic data indicates there is a large attic in terms of height and areal extent to the south, west and northwest of the Triceratops-2 well, which will be our focus during forward seismic acquisition and well programs on this field. Planning of new seismic and drilling location is in progress, and will be finalized once the remapping is complete. Although in the early stages of appraisal, an initial resource estimate of the Triceratops field has been included in our 2012 year end resource estimate, which is set forth in the 2012 Annual Information Form.

Management Discussion and Analysis   INTEROIL CORPORATION   5

· Pacific Rubiales Farm-In Agreement:

– On April 18, 2012, we signed a binding HOA with PRE for PRE to be able to earn a 10.0% net (12.9% gross) participating interest in the PPL 237 onshore PNG, 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. During the year, PRE has paid $40.0 million of the staged cash payments and subsequent to year end, in January 2013 a further $20.0 million of the staged cash payment was received. PRE has the option to terminate the HOA at various stages of the work program and to be reimbursed up to $96.0 million of the $116.0 million initial cash payment (which does not include carried costs) out of future upstream production proceeds.

– On July 27, 2012, we executed a Farm-In Agreement with PRE relating to the Triceratops structure and the participating interest in the PPL 237 license materially in line with the HOA signed. Completion of the farm-in transaction is subject to satisfaction of additional conditions within 18 months.

– On November 29, 2012, we executed the PRE JVOA and related documents associated with the Farm-In Agreement with PRE.

– Pac LNG are participating on a 25% beneficial equity basis in the portion of the farm-in transaction relating to the Triceratops structure (2.5% net and 3.2% gross participating interest), by reducing Pac LNG’s indirect participating interest in the Triceratops structure. Under this agreement, Pac LNG will receive credits (to be offset against cash call receivable for them for their IPI interest) for 25% of the payments PRE makes under the farm-in transaction relating to the Triceratops structure. Pac LNG will also receive a commission fee of 2.5% of cash payments made by PRE (other than carried costs). Certain other indirect participating interest holders may also participate in the farm-in transaction.

– Subsequent to year end, on January 24, 2013, the DPE approved and registered the transfer of interest in PPL 237 to PRE.

– The PPL 237 JV Operating Committee (“JVOC”) established with PRE will review and approve the forward work program, and submit an application for a PRL over the Triceratops discovery.

· Antelope field appraisal program

– On September 30, 2012, we spudded the Antelope-3 appraisal well in PRL 15. The Antelope-3 well is located approximately 1 kilometer south of the Antelope-1 well and 2.6 kilometers north of the Antelope-2 well. The primary objectives in drilling the Antelope-3 well were to confirm reservoir depth, composition, character and continuity, provide samples for analysis to further assist in development well planning, satisfy work program obligations for PRL 15 and complete the well as a future production well.

– On November 30, 2012, the top of the reservoir at the Antelope-3 well was penetrated at a depth of 5,328 feet (1,624 meters). This was 217 feet (66 meters) above the pre-drill estimate and 92 feet (28 meters) higher than the Antelope-1 well.

– On December 10, 2012, at a depth of 5,906 feet (1,800 meters) DST #1 in the Antelope-3 well showed natural gas and condensate. The well flowed at a maximum rate of 44.8 Mmscfpd with 10.4 to 14.9 barrels of condensate per million cubic feet through a 64/64 - inch choke. The analyzed gas composition is similar to the Antleope-1 and Antelope-2 wells. Total depth of 8,379 feet (2,554 meters) was attained on December 25, 2012.

– The preliminary independent analysis of the wireline log results demonstrated a carbonate reservoir (limestone and dolomite) with similar reefal reservoir character and quality as the offset Antelope-1 and Antelope-2 wells. The formation character is consistent with, and supplements, the results of our initial DST #1. Preliminary interpretation indicated that the Antelope-3 well shares the same water contact with these wells at 7,310 feet (2,228 meters) below sea level. With the top of the reservoir encountered at 5,328 feet (1,624 meters) measured depth in the well, equivalent to a true vertical depth of 5,009 feet (1,527 meters) below sea level, this equates to a hydrocarbon column height of approximately 2,301 feet (701 meters). This represents the tallest vertical column encountered in the Antelope field to date.

– Subsequent to year end, on January 24, 2013, we completed the logging program and as in the previous wells, conventional wireline logs (porosity, resistivity and sonic) were acquired in addition to formation imaging, vertical well bore seismic and rotary sidewall coring conducted while under pressure. The independent formation evaluation indicates an average porosity in the pay interval of 10.2% and a net to gross ratio of 66%. This compares favorably with the results from the Antelope-1 and Antelope-2 wells with average porosities of 8.8% and 13.1% respectively. We believe these results indicate that the reservoir quality at the Antelope-3 well location is of similar quality to the Antelope-1 and -2 wells, and fully support our reservoir model.

Management Discussion and Analysis   INTEROIL CORPORATION   6

– Production logging is in progress, and once this is complete, the well will be suspended for future completion as a production well.

· Elk field appraisal program:

– On October 26, 2012, our Rig#3 commenced mobilization to the Elk-3 well drill site following completion of the roadway from the Hou Creek supply base. Drilling of the Elk-3 development well is the final well required to satisfy the first two year work commitment on PRL 15.

– On November 27, 2012, we were notified by the DPE that it had been granted an approval of license variation to PRL 15, allowing us to defer the required drilling of a second commitment well from the first two year work program into the second two year work program.

· Seismic and exploration program:

– Kwalaha Phase 3 Seismic Data on PPL 236 and PPL 238 was acquired and analyzed during the second quarter of 2012, providing further understanding of the previously named Tuna and Wahoo prospects. Airborne gravity acquired in the second quarter of 2012 for PPL 236 and PPL 237 continues to be analyzed and added to previous airborne gravity data. Indications are of additional leads within PPL 236 and PPL 237 licenses, and these leads will be assessed for further seismic acquisition.

– Proposed well locations have currently been selected for Tuna and Wahoo prospects. Potential exploration well locations for future lease obligation wells were selected following completion of seismic acquisition, processing and mapping. However, with the success of the Triceratops gas discovery and the better than expected results of the Antelope-3 well, we have had discussions with the DPE on our forward focus and priorities. We believe that a clear mutual objective is focus on progressing the LNG Project. To progress development of our core assets, we have applied for variations to modify the well commitments for PPL 236 and PPL 238. We are awaiting formal variations in relation our commitments.

Midstream – Refining

· Total refinery throughput for the year ended December 31, 2012 was 24,483 barrels per operating day, compared with 24,856 barrels per operating day during the year ended December 31, 2011, and 24,682 barrels per operating day during 2010.

· Capacity utilization of the refinery for the year ended December 31, 2012, based on 36,500 barrels per day operating capacity, was 58% compared with 54% for 2011 and 53% for 2010. During the years ended December 31, 2012, 2011 and 2010, our refinery was shut down for 51 days, 82 days and 81 days, respectively, for general maintenance activities.

· The CRU, which allows the refinery to produce reformate for gasoline has been shutdown since August 3, 2012. During the year ended December 31, 2012, we produced gasoline for an interrupted period of 4 months, which was then supplemented by imports whilst the CRU was shutdown. We expect the CRU to be restarted in the second quarter of 2013 following the installation of a new catalyst.

· During the year, the BNP working capital facility was renewed for another year with a $10.0 million increase in the limit, bringing the total facility limit to $240.0 million to accommodate increasing volumes and crude prices.

· On October 16, 2012, we entered into a five year amortizing $100.0 million secured term loan facility with BNP, BSP, and ANZ). The loan is secured over the fixed assets of our refinery and bears interest at LIBOR plus 6.5%. The drawdown of the loan was completed on November 9, 2012.

· On November 9, 2012, part of the borrowings under the new term loan facility were used to repay all outstanding amounts under the term loan granted by OPIC.

Management Discussion and Analysis   INTEROIL CORPORATION   7

Midstream – Liquefaction

· Asset sell down process:

- Throughout the year, investment bankers led by Morgan Stanley & Company LLC, Macquarie Capital (USA) Inc. and UBS AG continued working on the bid process to seek a strategic partner to acquire an interest in the Elk and Antelope fields, the LNG Project and certain exploration licenses.

- Subsequent to year end, on January 24, 2013, we announced that we have advised bidders with whom we have been in discussions that the final binding bid solicitation period for the partnering process currently being undertaken will close on February 28, 2013. Our Board of Directors intends to meet our advisors during March 2013 for the purpose of evaluating bids received and selecting our partner(s) for the development of the LNG Project utilizing gas from the Elk and Antelope fields.

- We have made significant progress with pre-FEED and FEED engineering studies, construction of roads and camps, social mapping and genealogical studies, which will assist in the final partnering and project execution.

- During the year, we have extended the dates in the CSP agreements with Mitsui to provide flexibility for FID.

- During the year, we extended the dates in the contingent LNG Project agreements with EWC to provide flexibility for partner selection and FID.

- The conditional framework agreement with Samsung Heavy Industries and FLEX LNG related to the construction and operation of a planned 2 million tonnes per annum floating LNG processing vessel was not renewed.

· LNG Project Agreement:

- On November 16, 2012, we were notified by the Prime Minister of Papua New Guinea Hon. Peter O’Neill that the NEC had conditionally approved our LNG development project in the Gulf Province. This decision clears the way to proceed with our plans for the development of an LNG plant in the Gulf Province with initial planned output of a minimum of 3.8 million tonnes per annum. The decision also approves an option for the State to acquire an additional 27.5% interest in the Elk and Antelope gas fields, over and above the 22.5% interest to which it is entitled under the Oil & Gas Act, on terms to be negotiated with us. The NEC further approved the establishment of a State negotiating team to discuss and agree to the necessary amendments to the 2009 LNG Project Agreement between the State and Liquid Niugini Gas Limited, to give effect to the NEC decision, and to agree on the terms on which the State could acquire the additional interest. The NEC decision confirms that the basis of the acquisition will be on commercial market terms. The NEC decision also includes as a condition of its approval that the LNG plant operator must be an internationally recognized operator of the planned LNG facilities.

- The PNG Cabinet also approved the establishment of the Ministerial Gas Committee comprised of key economic ministers to fast track commercialization of the LNG Project.

Downstream

· The PNG economy continued to grow strongly throughout 2012 largely due to resource development projects, which has also led to growth in our aviation and retail businesses within our Downstream segments. Total sales volumes for year ended December 31, 2012 were 752.5 million litres (December 2011 – 678.0 million litres, December 2010 – 626.5 million litres), an increase of 74.5 million litres, or 11.0% over the same period in 2011.

· Our retail business accounted for approximately 15% of our total downstream sales in 2012 (2011 – 13%, 2010 - 15%). Investments have been made over the last three years in new electronic systems for both pumps and the forecourt control units to support the further development of this business. During 2012, one new retail site was opened as well as a truck stop commercial site. One existing retail site was purchased to secure tenure, and additional land was purchased for a future retail site.

· On December 14, 2012, the ICCC advised that margins for wholesale will increase in line with the ICCC mandated formula for a five year period. A consumer price index increase of 2.0% is reflected in these revised margins. These increases apply to unleaded gasoline, diesel and kerosene and are effective for the fiscal year ending December 31, 2013.

Management Discussion and Analysis   INTEROIL CORPORATION   8

· During the year, the Westpac working capital facility was increased by $4.8 million (PGK 10.0 million) bringing the total Downstream working capital facility to $66.6 million (PGK 140.0 million). In addition, a secured loan of $15.0 million was provided by Westpac which is repayable in equal installments over 3.5 years with an interest rate of LIBOR plus 4.4% per annum.

Corporate

· In March 2011, InterOil Corporate PNG Limited was incorporated under the laws of PNG, as a 100% subsidiary of InterOil Corporation to employ all corporate staff in PNG 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 will be recharged to relevant InterOil entities based on an equitable driver basis. This entity began transacting in October 2012.

SELECTED FINANCIAL INFORMATION AND HIGHLIGHTS

Consolidated Results for the Years Ended December 31, 2012, 2011 and 2010

Consolidated – Operating results	Year ended December 31,
($ thousands, except per share data)	2012			2011			2010
Sales and operating revenues		1,308,052			1,106,534			802,374
Interest revenue		248			1,356			151
Other non-allocated revenue		12,258			11,058			4,470
Total revenue		1,320,558			1,118,948			806,995
Cost of sales and operating expenses		(1,219,188	)		(1,020,932	)		(701,557	)
Office and administration and other expenses		(51,692	)		(52,793	)		(52,650	)
Derivative (loss)/gain		(4,229	)		2,006			(1,065	)
Exploration costs		(13,902	)		(18,435	)		(16,982	)
Gain on conveyance of oil and gas properties		4,418			-			2,141
Loss on extinguishment of IPI liability		-			-			(30,569	)
Litigation settlement expense		-			-			(12,000	)
Loss on Flex LNG Investment		-			(3,420	)		-
Foreign exchange (loss)/gain		(43	)		25,019			(10,777	)
EBITDA (1)		35,922			50,393			(16,464	)
Depreciation and amortization		(21,863	)		(20,137	)		(14,275	)
Interest expense		(23,166	)		(13,333	)		(7,364	)
(Loss)/profit before income taxes		(9,107	)		16,923			(38,103	)
Income tax benefit/(expense)		10,711			736			(6,410	)
Net profit/(loss)		1,604			17,659			(44,513	)
Net profit/(loss) per share (basic)		0.03			0.37			(1.00	)
Net profit/(loss) per share (diluted)		0.03			0.36			(1.00	)
Total assets		1,299,819			1,088,355			975,743
Total liabilities		523,762			328,464			272,841
Total long-term liabilities		190,838			128,072			130,323
Gross margin (2)		88,864			85,602			100,817
Cash flows (used in)/generated from operating activities(3)		(36,029	)		44,235			(30,543	)

Management Discussion and Analysis   INTEROIL CORPORATION   9

Notes:

(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 “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, and certain revisions made to the comparative period balances for the years ended December 31, 2011 and 2010.

Analysis of Financial Condition Comparing Years Ended December 31, 2012, 2011 and 2010

During the year ended December 31, 2012, our debt-to-capital ratio (being debt divided by [shareholders’ equity plus debt]) was 19% (12% as at December 31, 2011 and 13% as at December 31, 2010), 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, economic conditions, and are assessed regularly.

Our current ratio (being current assets divided by current liabilities), which measures our ability to meet short-term obligations, was 1.3 times as at December 31, 2012 (2.1 times as at December 31, 2011 and 3.2 times as at December 31, 2010). 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 0.7 times as at December 31, 2012 (1.3 times as at December 31, 2011 and 2.3 times as at December 31, 2010). These ratios were below our internal targets of above 1.5 times for the current ratio and 1.0 times for the quick ratio. The completion of the PRE farm-in transaction (expected to be completed during quarter ended March 31, 2013) and the closing of the transactions to sell down interests in the Elk and Antelope fields and the LNG Project, are expected to bring these ratios well within our internal targets.

As at December 31, 2012, our total assets amounted to $1,299.8 million, compared with $1,088.4 million as at December 31, 2011 and $975.7 million as at December 31, 2010. This increase of $211.4 million, or 19%, from December 31, 2011 was primarily due to further capitalization of expenditure on our oil and gas properties of $152.2 million associated with the appraisal and development of the Elk and Antelope fields including the drilling of Antelope-3 well, preparation and drilling of the Triceratops-2 well, Herd Base and Hou Creek infrastructure construction and continued development of the LNG Project; a $27.6 million increase in deferred tax benefits mainly related to the increase in refinery’s carried forward tax losses as at December 31, 2012, resulting from current year results and interest deductibility recognized subsequent to the payment of interest withholding tax in November 2012 on certain intercompany loan interest accrued from January 2007 to October 2012; a $23.8 million increase in inventory balances due to the timing of shipments; an increase in our trade and other receivables balance of $11.7 million on higher joint venture billings to upstream partners; and a $9.0 million increase in plant and equipment (after depreciation) from Downstream infrastructure upgrades across locations, Napa Napa camp, office building works and tank works. These increases were partially offset by the net decreases in our cash, cash equivalents, and restricted cash of $9.2 million and short term treasury bills of $11.8 million primarily due to expenditure on the development of oil and gas properties.

Comparing December 31, 2010 to December 31, 2011, the increase in total assets of $112.7 million or 12% was primarily due to further capitalization of expenditure on our oil and gas properties of $107.6 million associated with the appraisal and development of the Elk and Antelope fields, preparation for drilling the Triceratops-2 well, and continued development of the LNG Project.

As at December 31, 2012, our total liabilities amounted to $523.8 million, compared with $328.5 million at December 31, 2011 and $272.8 million at December 31, 2010. The increase of $195.3 million, or 59%, from December 31, 2011 was primarily due to a $77.8 million increase in working capital facilities payable (including trade receivables discounted with recourse); and a net increase of $75.4 million in secured loans payable on drawdown of the ANZ, BSP and BNP syndicated secured loan facility of $95.9 million (net of transaction costs) and drawdown of Westpac secured facility of $15.0 million, OPIC loan repayment of $35.5 million and Westpac’s secured loan principal repayment of $2.1 million made during the year; an increase of $20.1 million in accounts payable and accrued liabilities, mainly related to timing of payments on certain crude cargo purchases; a receipt of the $20.0 million staged cash payment under the advance payment facility from PRE held as a liability due to their option to exit the Farm-In Agreement; and a $7.9 million increase in income tax payable on increased profits in our Downstream segment. These increases however have been partially offset by the decrease of deferred gain on contribution to LNG project by $5.8 million as this has now been fully offset against the capitalized project costs held within Midstream – Liquefaction segment, and a $3.0 million reduction in IPI liability mainly attributed to the waiver or forfeiture of 1.5% IPI interest conversion rights into common shares during the year.

Management Discussion and Analysis   INTEROIL CORPORATION   10

Comparing December 31, 2010 to December 31, 2011, the increase of $55.7 million, or 20%, was primarily due to an increase in accounts payable and accrued liabilities of $84.7 million, offset in part by a reduction of $34.8 million in the working capital facility which is mainly a function of timing of crude purchases for the refining operation.

Analysis of Consolidated Financial Results Comparing Quarters ended December 31, 2012 and 2011, and Years ended December 31, 2012, 2011 and 2010

Quarterly Comparative

Our net profit for the quarter ended December 31, 2012 was $18.5 million compared with a net profit of $13.2 million for the same quarter of 2011, an increase of $5.3 million. The operating segments of Corporate, Midstream Refining and Downstream collectively derived a net profit for the quarter of $32.0 million, while the investments in development segments of Upstream and Midstream Liquefaction resulted in a net loss of $13.5 million.

The improvement in net profit for the fourth quarter in 2012 as compared to 2011 was mainly due to a $26.0 million increase in gross margin attributable to the improved crude and product price movements, higher margins from export cargos, and lower premium and freight paid for the purchased crudes during the quarter; a $2.6 million reduction of exploration costs incurred for seismic activity for PPL 236; a $1.6 million decrease in the loss on available-for-sale investment in the shares in FLEX LNG, and a $1.6 million increase in gain on conveyance of oil and gas properties recognized due to the waiver or forfeiture of 1.5% IPI interest conversion rights into common shares.

These increases in profit was partly offset by a $11.4 million reduction in foreign exchange gain, mainly due to the weakening of PGK against USD (foreign exchange rate decreased from 0.4805 to 0.4755) compared to fourth quarter of 2011 (foreign exchange rate increased from 0.4465 to 0.4665); a $9.5 million increase in borrowing costs relates primarily to the $9.7 million withholding tax paid in November 2012 for intercompany loan interests incurred from January 2007 to October 2012; and a $6.0 million decrease in income tax benefit resulting from the taxable temporary differences, which in the prior year was mainly arising from the translation of the non-monetary assets of the refinery operation using period end rates (strengthening of PGK against USD was higher in prior year quarter).

Total revenues increased by $66.8 million from $289.6 million in the quarter ended December 31, 2011 to $356.4 million in the quarter ended December 31, 2012, primarily due to higher sales volumes made during the year. The total volume of all products sold by us was 2.3 million barrels for quarter ended December 31, 2012, compared with 1.9 million barrels in the same quarter of 2011.

Annual Comparative

Our net profit for the year ended December 31, 2012 was $1.6 million compared with $17.7 million for the same period of 2011, a decrease of $16.1 million, while a net loss for the same period of 2010 was $44.5 million. The operating segments of Corporate, Midstream Refining and Downstream collectively derived a net profit for the year ended December 31, 2012 of $61.2 million, while the investments in development segments of Upstream and Midstream Liquefaction resulted in a net loss of $59.6 million.

The decrease in net profit for the year 2012 compared to the year 2011 of $16.1 million was mainly due to a $25.1 million decrease in foreign exchange gain, due to the PGK being relatively stable in the year ended December 31, 2012 (foreign exchange rate increased from 0.4665 to 0.4755) compared to same period in 2011 when it strengthened significantly (foreign exchange rate increased from 0.3785 to 0.4665); a $9.8 million increase in interest expense, resulting from the $9.7 million interest withholding tax paid in November 2012 for certain intercompany loan interests accrued from January 2007 to October 2012 and settled in November 2012; and a $6.3 million decrease in derivative gain, primarily from the losses incurred for the commodity contracts settled in September 2012. These decreases in profit have been partly offset by a $10.0 million increase in income tax benefits resulting mainly from current year results and interest deductibility recognized subsequent to the payment of interest withholding tax in November 2012 on certain intercompany loan interest accrued from January 2007 to October 2012; a $4.5 million reduction in exploration costs incurred for seismic activity for PPL 236; a $4.4 million increase in gain on conveyance of oil and gas properties, which was recognized on sale of interest in PPL 237 to PRE and the waiver or forfeiture of 1.5% IPI interest conversion rights into common shares. In addition, an improvement of $3.3 million in gross margin on account of the increased pricing due to ICCC price revisions in fourth quarter of 2011, and increasing Downstream domestic sales volumes resulting from various development projects being undertaken in Papua New Guinea has further lessened the unfavorable movement in current year profit.

Management Discussion and Analysis   INTEROIL CORPORATION   11

Net profit for the year ended December 31, 2011 was $17.7 million compared with a net loss of $44.5 million for 2010, an improvement of $62.2 million. The main items contributing towards the loss in 2010 were one time charges including a loss on extinguishment of IPI liability of $30.6 million and a $12.0 million expense relating to settlement of certain long-standing litigation. Foreign exchange gains also increased in 2011 by $35.8 million compared to 2010 due to the PGK strengthening against the USD from 0.3785 at the start of the year to 0.4665 as at December 31, 2011.

Total revenues increased by $201.6 million from $1,118.9 million in the year ended December 31, 2011 to $1,320.6 million in the year ended December 31, 2012, primarily due to higher volumes and export prices during the period. Total revenues in the year ended December 31, 2010 were $807.0 million. The total volume of all products sold by us was 8.5 million barrels for year ended December 31, 2012, compared with 7.4 million barrels in the same period of 2011, and 7.2 million barrels in 2010.

The Upstream segment realized a net loss of $56.8 million in 2012 (2011 – loss of $49.1 million, 2010 – loss of $78.6 million). The increase in the loss in 2012 by $7.7 million from 2011 was mainly due to an increase of $13.1 million on intercompany interest charges due to higher loan balances from the parent entity (Corporate segment) to fund the exploration and development activities. During 2012, there has also been an increase in office and administration expenses of $6.8 million as a result of increased operating expenses associated with the operation of the construction and logistics departments. These increases have been offset by a $4.5 million reduction in exploration costs incurred for seismic activity on PPL 236, and a $4.4 million increase in gain on conveyance of oil and gas properties recognized on sale of interest in PPL 237 to PRE, and the waiver or forfeiture of 1.5% IPI interest conversion rights into common shares. The reduction in the loss in 2011 by $29.4 million from 2010 was mainly due to one-time events in 2010 of $30.6 million loss on extinguishment of IPI liability and offset partly by a $2.1 million gain on conveyance of oil and gas properties.

The Midstream Refining segment generated a net loss of $2.9 million in 2012 (2011 – profit of $46.7 million, 2010 – profit of $33.5 million) mainly due to lower gross margins (a decrease of $17.4 million from 2011) from negative crude and product price movements particularly during the quarter ended June 30, 2012, increases in premiums and freight paid on crude purchases and lower distillate yields on available crude cargoes; a $34.3 million decrease in foreign exchange gain, mainly due to the PGK being relatively stable in the year ended December 31, 2012 (foreign exchange rate increased from 0.4665 to 0.4755) compared to 2011 (foreign exchange rate increased from 0.3785 to 0.4665); a $8.2 million increase in interest expense, mainly resulting from the $9.7 million interest withholding tax paid in November 2012 for certain intercompany loan interests accrued from January 2007 to October 2012 and settled in November 2012; and a $6.3 million decrease in derivative gain, primarily from the losses incurred for the commodity contracts settled in September 2012. These decreases have been partly offset by a $18.8 million increase in income tax benefits resulting mainly from current year results and interest deductibility recognized subsequent to the payment of interest withholding tax in November 2012 on certain intercompany loan interest accrued from January 2007 to October 2012. The net profit in 2011 increased from 2010 mainly on account of a $34.0 million increase in foreign exchange gains as a result of rising PGK against USD during 2011, which were partially offset by lower gross margins on decreases in export product crack spreads on increased crude costs and reduced demand for export products.

The Midstream Liquefaction segment had a net loss of $2.8 million during the 2012 year (2011 – loss of $15.5 million, 2010 – loss of $8.4 million) resulting from lower management expenses and share compensation costs related to the midstream facilities of the LNG Project development which are not capitalized. The decrease in expenses from prior year is in line with reduced expenditure being approved till the sell down process is completed, to seek a strategic partner to acquire an interest in the Elk and Antelope fields, the LNG Project and well exploration licenses, is completed.

Management Discussion and Analysis   INTEROIL CORPORATION   12

The Downstream segment generated a net profit of $32.6 million in 2012 (2011 – profit of $11.6 million, 2010 – profit of $6.7 million). The increased profit was mainly due to a $23.1 million improvement in gross margins on increased domestic sales volumes resulting from various development projects being undertaken in Papua New Guinea, and a $8.5 million increase in foreign exchange gain mainly due to the required 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 quarter ended March 31, 2012. This improvement in profit has been partly offset by an $8.6 million increase in income tax expense on account of higher operating profits for the year. The increased profit in 2011 compared to 2010 was mainly due to a $5.6 million improvement in gross margins due to an increase in domestic volumes and the positive impact from the revised pricing formula that came into effect in late 2010 following the ICCC’s review of wholesale, distribution and retail margins set by the PNG State for the petroleum industry, and the impact of the increasing price environment during the period leading to higher margins on inventories sold.

The Corporate segment generated a net profit of $33.1 million in 2012 (2011 – profit of $21.9 million, 2010 – profit of $3.3 million). The increased profit was mainly on account of a $10.7 million increase in interest charges to other business segments on increased loan balances and due to a $3.4 million impairment loss recognized in 2011 on our investment in shares in Flex LNG held by us as part of the framework agreements entered into with FLEX LNG and Samsung Heavy Industries in April 2011. The 2010 results included a $12.0 million one time litigation settlement expense on account of the agreed settlement of the Todd Peters et al litigation for which we issued 199,677 common shares to the plaintiffs.

Variance Analysis

A complete discussion of each of our business segments’ results can be found under the section “Quarter and Year 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 years ended December 31, 2012 and 2011.

Management Discussion and Analysis   INTEROIL CORPORATION   13

Quarterly Variance ($ millions)		Yearly Variance ($ millions)
	$5.3	($16.1)	Net profit/(loss) variance for the comparative period primarily due to:
Ø	$26.0	$3.3	Increase in gross margin for the year ended December 31, 2012 was mainly due to the following contributing factors: +    Higher Downstream domestic sales volumes resulting from various development projects being undertaken in Papua New Guinea +    Increased margins on export cargos – light and heavy Naphtha +    Increased pricing due to ICCC yearly price revisions in fourth quarter of 2011 -    Losses due to negative crude and product price movements between periods, particular during quarter ended June 30, 2012 when we had a high inventory due to certain weather or supply factors, resulting in higher net realizable value write downs -    Increases in premiums and freight paid on purchased crudes Increase in gross margin for the current quarter ended December 31, 2012 was mainly due to the following contributing factors: +    Gains due to decreases in premiums and freight paid on purchased crudes +    Gains due to improved crude and product price movements during the current quarter compared to the same period in 2011 +    Increased margins on export cargos
Ø	($1.3)	$1.1	Lower office and administration and other expenses were primarily resulted from lower management expenses and share compensation costs related to the midstream facilities of the LNG Project development which were not capitalized.
Ø	($0.0)	($6.2)	Higher derivative losses for the year attributed to the losses on commodity contracts settled in September 2012.
Ø	$2.6	$4.5	Lower exploration costs incurred for seismic activity for PPL 236 during the periods. The seismic costs were in relation to the Kwalaha and Tuna seismic acquisition programs.
Ø	$1.5	$4.4	The increase in gain on conveyance of oil and gas properties for the year was attributable to the gain recognized on sale of interest in PPL 237 to PRE, and the waiver or forfeiture of 1.5% IPI interest conversion rights into common shares.
Ø	$1.6	$3.4	Decrease in loss on available-for-sale investment due to the impairment losses recognized in prior periods for the reduction in fair value of the FLEX LNG investment.
Ø	($11.4)	($25.1)	Decrease in foreign exchange gains for the year was mainly due to the PGK being relatively stable in the year ended December 31, 2012 (foreign exchange rate increased from 0.4665 to 0.4755) compared to same period in 2011 (foreign exchange rate increased from 0.3785 to 0.4665) and a reduction in exchange gains held on PGK cash balances with the maturity of various term deposits since second quarter of 2011. Decrease in foreign exchange gains for the quarter was primarily resulted by the weakening of PGK against USD (foreign exchange rate decreased from 0.4805 to 0.4755) compared to fourth quarter of 2011 (foreign exchange rate increased from 0.4465 to 0.4665).
Ø	($9.5)	($9.8)	Increase in interest expense for both periods was mainly due to $9.7 million interest withholding tax paid in November 2012 for certain intercompany loan interest accrued from January 2007 to October 2012 and settled in November 2012.
Ø	($6.0)	$10.0	Increase in income tax benefits for the year primarily attributable to the increased refinery carried forward tax losses, and interest deductibility recognized subsequent to the payment of interest withholding tax in November 2012 on certain intercompany loan interest accrued from January 2007 to October 2012. Decrease in income tax benefits for the quarter primarily resulting from the impact of unfavorable foreign exchange movements impacting temporary differences on translation of the nonmonetary assets of the refinery operation using period end rates.

Management Discussion and Analysis   INTEROIL CORPORATION   14

Analysis of Consolidated Cash Flows Comparing Quarters Ended December 31, 2012 and 2011, and Years Ended December 31, 2012, 2011 and 2010

As at December 31, 2012, we had cash, cash equivalents, and restricted cash of $98.9 million (December 31, 2011 – $108.1 million, December 31, 2010 - $280.9 million), of which $49.0 million (December 31, 2011 - $39.3 million, December 31, 2010 - $47.3 million) was restricted. Of the total restricted cash of $49.0 million, $37.3 million (December 31, 2011 - $33.0 million, December 31, 2010 - $40.7 million) was restricted pursuant to the BNP Paribas working capital facility utilization requirements, $11.3 million (December 31, 2011 – $5.9 million, December 31, 2010 - $6.3 million) was restricted as a cash deposit on the secured loans (ANZ, BSP and BNP syndicated secured loan facility as at December 31, 2012, and OPIC facility as at December 31, 2011 and 2010), and the balance was made up of a cash deposit on office premises together with term deposits on our PPLs.

A revision of the prior period comparatives for the years ended December 31, 2011 and 2010 and the respective interim periods for those years have been made to the Statement of Cash Flows for revising the classification of oil and gas properties expensed (exploration costs, excluding exploration impairment) to an operating activity in the Statement of Cash Flows, as opposed to our earlier classification of this item as an investing activity. This revision was made as we had failed to consider the specific IFRIC clarification to IAS 7, effective January 1, 2010 that confirmed that only expenditures that result in a recognized asset in the balance sheet being eligible for classification as investing activities. Please refer to “Liquidity and Capital Resources – Summary of Cash Flows” section for further details.

Cash flows from operations

Our cash outflows from operations for the quarter ended December 31, 2012 were $27.7 million compared with an inflow of $26.3 million for the quarter ended December 31, 2011, a net increase in cash outflows of $54.0 million. This increase in cash outflows was mainly due to a $65.6 million net increase in working capital outflows associated with trade and other receivables, inventories and accounts payables and a $11.6 million increase in net cash inflow used in operations prior to changes in operating working capital, related to the net profit generated by the operations less any non-cash expenses for the quarter ended December 31, 2012.

Our cash outflows from operations for the year ended December 31, 2012 were $36.0 million compared with an inflow of $44.2 million for the year ended December 31, 2011, a net increase in cash outflows of $80.2 million. This increase in cash outflows was mainly due to a $31.4 million net increase in working capital outflows associated with trade and other receivables, inventories and accounts payables and a $48.8 million decrease in net cash inflow generated from operations prior to changes in operating working capital, related to the lower profits generated by the operations less any non-cash expenses for the year ended December 31, 2012.

Our cash inflows from operations for the year ended December 31, 2011 were $44.2 million compared with outflows of $30.5 million for the year ended December 31, 2010, a net increase in cash inflows of $74.7 million.  This increase in cash inflows is mainly due to a $24.6 million change in cash generated by operations prior to changes in operating working capital, related to higher profits generated from operations less any non-cash expenses for the year.  There was also a $50.1 million decrease in working capital associated with trade receivables, inventories and accounts payables. 

Cash flows from investing activities

Cash outflows for investing activities for the quarter ended December 31, 2012 were $52.3 million compared with $41.4 million for the quarter ended December 31, 2011. These outflows mainly relate to the net cash expenditures on exploration, appraisal and development activities (net of IPI cash calls) of $34.9 million, expenditures on plant and equipment of $10.6 million and a $9.4 million increase in restricted cash held as security under BNP Paribas working capital facility and ANZ, BSP and BNP syndicated secured loan facility. These outflows were partly offset by a $2.6 million decrease in working capital requirements of development segments relating to the timing of payments.

Cash outflows for investing activities for the year ended December 31, 2012 were $169.7 million compared with $185.8 million for the year ended December 31, 2011. These outflows mainly relate to the net cash expenditures on exploration, appraisal and development activities (net of IPI cash calls) of $180.7 million, expenditures on plant and equipment of $36.7 million and a $9.8 million increase in restricted cash held as security under BNP Paribas working capital facility and ANZ, BSP and BNP syndicated secured loan facility. These outflows were partly offset by the receipt of $20.0 million non-refundable initial staged cash proceeds from PRE for the sell down of a net 10.0% (12.9% gross) participating interest in PPL 237; maturity of short term PGK treasury bills of $11.8 million during the year; and a $25.5 million increase in working capital requirements of development segments relating to the timing of payments.

Management Discussion and Analysis   INTEROIL CORPORATION   15

Cash outflows for investing activities for the year ended December 31, 2011 were $185.8 million compared with $94.2 million for the year ended December 31, 2010.  These outflows mainly relate to the net cash expenditure on exploration, appraisal and development activities (net of IPI cash calls) of $115.7 million, expenditure on plant and equipment of $42.1 million, acquisition of FLEX LNG shares net of transaction costs of $7.5 million, investments in short term PGK treasury bills of $11.8 million, a $10.0 million increase in trade receivables and a $6.7 million decrease in working capital requirements of development segments relating to the timing of receipts and payments.  These outflows were partly offset by a decrease of $8.0 million in the restricted cash balance under the BNP Paribas working capital facility.

Cash flows from financing activities

Cash inflows from financing activities for the quarter ended December 31, 2012 amounted to $72.5 million, compared with outflows of $31.9 million for the quarter ended December 31, 2011. The increase in these cash inflows are primarily due to the $95.9 million drawdown of ANZ, BSP and BNP syndicated secured loan facility (net of transaction costs); a $7.2 million increase in proceeds from the Westpac, BSP and BNP working capital facilities; and a $0.4 million increase in receipts of cash from the exercise of stock options by employees under our stock incentive plan. These increases have been partially offset by the repayment of OPIC secured loan of $31.0 million.

Cash inflows from financing activities for the year ended December 31, 2012 amounted to $185.7 million, compared with outflows of $27.2 million for the year ended December 31, 2011. The increase in these cash inflows are primarily due to the $95.9 million drawdown of ANZ, BSP and BNP syndicated secured loan facility (net of transaction costs); a $77.8 million increase in proceeds from the Westpac, BSP and BNP Paribas working capital facilities; the receipt of $20.0 million advance payment facilities received from PRE for the sell down of a net 10.0% (12.9% gross) participating interest in PPL 237 in accordance with the Farm-In Agreement; a $15.0 million increase from the drawdown of the Westpac secured loan facility; a $11.0 million increase in receipts of cash from the exercise of stock options by employees under our stock incentive plan; and an increase of $3.6 million receipts of cash contribution from Mitsui for the Condensate Stripping Project. These increases have been partially offset by the full repayment of OPIC secured loan of $35.5 million and semi-annual Westpac secured loan principal repayment of $2.1 million.

Cash outflows from financing activities for the year ended December 31, 2011 amounted to $27.2 million, compared with $311.8 million inflows for the year ended December 31, 2010. These cash outflows include two repayments of the OPIC secured loan of $9.0 million and $34.8 million repayments of the working capital facility. These outflows have been partly offset by receipts of cash contributions from Mitsui for the Condensate Stripping Project of $9.9 million, receipts from PNG LNG cash call of $2.2 million, and receipts of cash from the exercise of stock options of $4.5 million. The cash inflows/outflows associated with the working capital facility drawdown/repayments are due to the timing of cash flows and the use of working capital. The inflows from financing activities in the prior year relate primarily to the receipt of cash from the concurrent common share and 2.75% convertible note public offerings in November 2010.

Management Discussion and Analysis   INTEROIL CORPORATION   16

Summary of Consolidated Quarterly Financial Results for Past Eight Quarters

The following is a table containing the consolidated results for the eight quarters ended December 31, 2012 by business segment, and on a consolidated basis.

Quarters ended	2012												2011
($ thousands except per share data)	Dec-31			Sep-30			Jun-30			Mar-31			Dec-31			Sep-30			Jun-30			Mar-31
Upstream		4,136			2,216			1,727			2,284			1,891			2,645			4,638			668
Midstream – Refining		301,925			274,671			236,006			302,310			237,640			231,455			262,111			217,743
Midstream – Liquefaction		-			-			-			-			-			-			-			-
Downstream		220,512			201,749			223,620			218,974			209,678			186,304			191,431			157,709
Corporate		37,552			26,880			24,742			24,757			21,831			25,078			26,548			18,659
Consolidation entries		(207,686	)		(178,652	)		(186,991	)		(210,174	)		(181,428	)		(163,584	)		(180,945	)		(151,125	)
Total revenues		356,439			326,864			299,104			338,151			289,612			281,898			303,783			243,654
Upstream		(873	)		956			(5,730	)		(6,374	)		665			(6,169	)		593			(10,957	)
Midstream – Refining		12,370			13,417			(42,647	)		18,933			2,604			3,461			27,967			26,632
Midstream – Liquefaction		192			11			676			(1,406	)		(4,123	)		(3,602	)		(4,035	)		(2,375	)
Downstream		12,258			9,275			11,102			21,414			6,808			3,570			5,777			8,744
Corporate		14,133			9,841			9,975			9,188			10,134			1,548			13,940			5,223
Consolidation entries		(12,199	)		(14,503	)		(9,871	)		(14,216	)		(11,280	)		(10,263	)		(5,269	)		(9,200	)
EBITDA (1)		25,881			18,997			(36,495	)		27,539			4,808			(11,455	)		38,973			18,067
Upstream		(13,081	)		(10,936	)		(15,532	)		(17,244	)		(9,402	)		(15,080	)		(6,703	)		(17,949	)
Midstream – Refining		13,401			5,358			(32,969	)		11,320			15,684			(1,201	)		17,314			14,894
Midstream – Liquefaction		(394	)		(573	)		93			(1,969	)		(4,574	)		(3,980	)		(4,309	)		(2,604	)
Downstream		7,716			5,626			6,045			13,195			3,621			1,146			2,306			4,491
Corporate		10,519			7,849			8,445			6,270			7,616			(473	)		11,275			3,463
Consolidation entries		384			(1,988	)		2,205			(2,136	)		252			(190	)		3,657			(1,596	)
Net profit/(loss)		18,545			5,336			(31,713	)		9,436			13,197			(19,778	)		23,540			699
Net profit/(loss) per share (dollars)
Per Share – Basic		0.38			0.11			(0.66	)		0.20			0.27			(0.41	)		0.49			0.01
Per Share – Diluted		0.38			0.11			(0.66	)		0.19			0.27			(0.41	)		0.48			0.01

(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   17

QUARTER AND YEAR IN REVIEW

The following section provides a review of the quarter and year ended December 31, 2012 for each of our business segments.

UPSTREAM – QUARTER AND YEAR IN REVIEW

Upstream – Operating results	Quarter ended December 31,						Year ended December 31,
($ thousands)	2012			2011			2012			2011
Other non-allocated revenue		4,136			1,891			10,363			9,841
Total revenue		4,136			1,891			10,363			9,841
Office and administration and other expenses		(7,274	)		1,555			(11,970	)		(5,122	)
Exploration costs		758			(1,799	)		(13,902	)		(18,435	)
Gain on conveyance of oil and gas properties		1,523			-			4,418			-
Foreign exchange loss		(16	)		(982	)		(930	)		(2,153	)
EBITDA (1)		(873	)		665			(12,021	)		(15,869	)
Depreciation and amortization		(474	)		(1,355	)		(1,675	)		(3,255	)
Interest expense		(11,734	)		(8,712	)		(43,097	)		(30,013	)
Loss before income taxes		(13,081	)		(9,402	)		(56,793	)		(49,137	)
Income tax expense		-			-			-			-
Net loss		(13,081	)		(9,402	)		(56,793	)		(49,137	)

(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   18

Analysis of Upstream Financial Results Comparing the Quarters and Years Ended December 31, 2012 and 2011

The following analysis outlines the key movements, the net of which primarily explains the variance in the results between the quarters and years ended December 31, 2012 and 2011.

Quarterly Variance ($ millions)		Yearly Variance ($ millions)
	($3.7)	($7.7)	Net loss variance for the comparative period primarily due to:
Ø	$2.2	$0.5	Other non-allocated revenue relates to the utilization of construction and drilling related activities performed internally, including civil works and related infrastructure development associated with the LNG Project. 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.
Ø	($8.8)	($6.8)	Increase in office and administration expenses for the periods was mainly due to increased operating expenses associated with the operation of the construction and logistics departments.
Ø	$2.6	$4.5	Reduction in exploration costs incurred for seismic activity for PPL 236 during the 2012 periods. The seismic costs were in relation to the Kwalaha and Tuna seismic acquisition programs.
Ø	$1.5	$4.4	The increase in gain on conveyance of oil and gas properties for the year was attributable to the gain recognized on sale of interest in PPL 237 to PRE, and the waiver or forfeiture of 1.5% IPI interest conversion rights into common shares. The increase in gain on conveyance of oil and gas properties for the quarter was attributable to the gain recognized on the waiver or forfeiture of 1.5% IPI interest conversion rights as noted above.
Ø	$1.0	$1.2	Foreign exchange movements during the year mainly due to currency fluctuations between the PGK and the USD. PGK had been relatively stable in the year ended December 31, 2012 (foreign exchange rate increased from 0.4665 to 0.4755) compared to same period in 2011 (foreign exchange rate increased from 0.3785 to 0.4665), which had led to lesser foreign exchange losses incurred for PGK payments made during the year and PGK denominated liabilities recorded as at year end.
Ø	($3.0)	($13.1)	Higher interest expense due to an increase in inter-company loan balances provided to fund exploration and development activities.

MIDSTREAM - REFINING – QUARTER AND YEAR IN REVIEW

Midstream Refining – Operating results	Quarter ended December 31,						Year ended December 31,
($ thousands)	2012			2011			2012			2011
External sales		131,768			77,591			445,120			362,606
Inter-segment revenue - Sales		169,183			156,868			650,805			576,672
Inter-segment revenue - Recharges		967			2,826			18,803			8,841
Interest and other revenue		7			355			185			831
Total segment revenue		301,925			237,640			1,114,913			948,950
Cost of sales and operating expenses		(283,432	)		(235,339	)		(1,071,852	)		(897,825	)
Office and administration and other expenses		(2,811	)		(5,735	)		(28,927	)		(18,939	)
Derivative gain/(loss)		486			201			(4,241	)		2,018
Foreign exchange (loss)/gain		(3,798	)		5,837			(7,824	)		26,458
EBITDA (1)		12,370			2,604			2,069			60,662
Depreciation and amortization		(4,153	)		(2,878	)		(12,859	)		(11,254	)
Interest expense		(11,390	)		(3,285	)		(17,825	)		(9,664	)
(Loss)/profit before income taxes		(3,173	)		(3,559	)		(28,615	)		39,744
Income tax benefit		16,574			19,243			25,722			6,946
Net profit/(loss)		13,401			15,684			(2,893	)		46,690
Gross Margin (2)		17,519			(880	)		24,073			41,453

(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   19

Midstream - Refining Operating Review

	Quarter ended December 31,						Year ended December 31,
Key Refining Metrics	2012			2011			2012			2011
Throughput (barrels per day)(1)		26,438			24,644			24,483			24,856
Capacity utilization (based on 36,500 barrels per day operating capacity)		58	%		50	%		58	%		54	%
Cost of production per barrel	$	3.73		$	5.18		$	4.40		$	4.58
Working capital financing cost per barrel of production	$	0.57		$	0.76		$	0.67		$	0.73
Distillates as percentage of production		47.4	%		57.1	%		55.1	%		57.5	%

(1) Throughput per day has been calculated excluding shut down days. During year 2012 and 2011, the refinery was shut down for 51 days and 82 days, respectively.

Analysis of Midstream - Refining Financial Results Comparing the Quarters and Years ended December 31, 2012 and 2011

The following analysis outlines the key movements, the net of which primarily explains the variance in the results between the quarters and years ended December 31, 2012 and 2011.

Quarterly Variance ($ millions)		Yearly Variance ($ millions)
	($2.3)	($49.6)	Net profit/(loss) variance for the comparative period primarily due to:
Ø	$18.4	($17.4)	Decrease in gross margin for the year was mainly due to the following contributing factors: -    Losses due to negative crude and product price movements, particularly during quarter ended June 30, 2012 -    Increases in premiums and freight paid on purchased crudes, while yield was marginally lower -    Increased direct cost of sale expenses, including insurance, repair and maintenance and labour costs. +Increased margins on export cargos – light and heavy Naphtha      Increase in gross margin for the quarter was mainly due to the following contributing factors: +Gains due to decreases in premiums and freight paid on purchased crudes, which is partially offset by lower yield structure (i.e. reduced distillate yield) +Gains due to positive crude and product price movements during the quarter +  Increased margins on export cargos
Ø	$0.3	($6.3)	Increase in derivative loss for the year was mainly resulting from the losses incurred for the commodity contracts settled in September 2012.
Ø	($9.6)	($34.3)	Decrease in foreign exchange gains for the year was mainly due to the PGK being relatively stable in the year ended December 31, 2012 (foreign exchange rate increased from 0.4665 to 0.4755) compared to same period in 2011 (foreign exchange rate increased from 0.3785 to 0.4665) and a reduction in exchange gains held on PGK cash and treasury bill balances which matured in the second quarter of 2011. Decrease in foreign exchange gains for the quarter was primarily resulted by the weakening of PGK against USD (foreign exchange rate decreased from 0.4805 to 0.4755) compared to fourth quarter of 2011 (foreign exchange rate increased from 0.4465 to 0.4665).
Ø	($1.3)	($1.6)	Increase in depreciation and amortization was primarily due to the depreciation charge for the capital additions, e.g. upgraded Napa Napa camp and building works.
Ø	($8.1)	($8.2)	Increase in interest expense for both periods was mainly attributable to the $9.7 million interest withholding tax paid in November 2012 for certain intercompany loan interest accrued from January 2007 to October 2012 and settled in November 2012.
Ø	($2.7)	$18.8	Increase in income tax benefits for the year primarily attributed to the increased refinery’s carried forward tax losses, and interest deductibility recognized subsequent to the payment of interest withholding tax in November 2012 on certain intercompany loan interest accrued from January 2007 to October 2012. Decrease in income tax benefits for the quarter was mainly due to the impact of unfavorable foreign exchange movement for PGK against USD in fourth quarter of 2012 as compared to the favorable foreign exchange movement for PGK against USD in fourth quarter of 2011, which impacted temporary differences on translation of the non-monetary assets of the refinery operation using period end rates.

Management Discussion and Analysis   INTEROIL CORPORATION   20

MIDSTREAM - LIQUEFACTION – QUARTER AND YEAR IN REVIEW

Midstream Liquefaction – Operating results	Quarter ended December 31,						Year ended December 31,
($ thousands)	2012			2011			2012			2011
Interest and other revenue		-			-			-			-
Total segment revenue		-			-			-			-
Office and administration and other expenses		192			(4,128	)		(525	)		(14,121	)
Foreign exchange gain/(loss)		-			5			(3	)		(13	)
EBITDA (1)		192			(4,123	)		(528	)		(14,134	)
Depreciation and amortization		-			(6	)		(8	)		(26	)
Interest expense		(586	)		(445	)		(2,308	)		(1,308	)
Loss before income taxes		(394	)		(4,574	)		(2,844	)		(15,468	)
Income tax expense		-			-			-			-
Net loss		(394	)		(4,574	)		(2,844	)		(15,468	)

(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   21

Analysis of Midstream - Liquefaction Financial Results Comparing the Quarters and Year ended December 31, 2012 and 2011

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

The following analysis outlines the key movements, the net of which primarily explains the variance in the results between the quarters and years ended December 31, 2012 and 2011.

	Quarterly Variance ($ millions)	Yearly Variance ($ millions)
	$4.2	$12.6	Net loss variance for the comparative period primarily due to:
Ø	$4.3	$13.6	Decrease in office, administration and other expenses was due to lower management expenses and share compensation costs related to the midstream facilities of the LNG Project development which are not capitalized.

DOWNSTREAM – QUARTER AND YEAR IN REVIEW

Downstream – Operating results	Quarter ended December 31,						Year ended December 31,
($ thousands)	2012			2011			2012			2011
External sales		219,892			209,389			862,736			743,663
Inter-segment revenue - Sales		59			18			222			197
Interest and other revenue		561			271			1,898			1,263
Total segment revenue		220,512			209,678			864,856			745,123
Cost of sales and operating expenses		(203,202	)		(199,867	)		(800,217	)		(704,213	)
Office and administration and other expenses		(4,897	)		(4,665	)		(18,815	)		(15,780	)
Foreign exchange (loss)/gain		(155	)		1,662			8,227			(229	)
EBITDA (1)		12,258			6,808			54,051			24,901
Depreciation and amortization		(1,135	)		(1,422	)		(5,082	)		(4,026	)
Interest expense		(337	)		(1,170	)		(2,871	)		(4,346	)
Profit before income taxes		10,786			4,216			46,098			16,529
Income tax expense		(3,070	)		(595	)		(13,512	)		(4,962	)
Net profit		7,716			3,621			32,586			11,567
Gross Margin (2)		16,749			9,540			62,741			39,647

(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   22

Downstream Operating Review

	Quarter ended December 31,				Year ended December 31,
Key Downstream Metrics	2012			2011		2012		2011
Sales volumes (millions of liters)		188.8		187.7		752.5		678.0
Average sales price per liter	$	2.37	$	2.43	$	2.32	$	2.55

Analysis of Downstream Financial Results Comparing the Quarters and Year ended December 31, 2012 and 2011

The following analysis outlines the key movements, the net of which primarily explains the variance in the results between the quarters and years ended December 31, 2012 and 2011.

Quarterly Variance ($ millions)		Yearly Variance ($ millions)
	$4.1	$21.0	Net profit variance for the comparative period primarily due to:
Ø	$7.2	$23.1	Gross margins increased compared to the prior year periods mainly due to an increase in domestic sales volumes resulting from various development projects being undertaken in Papua New Guinea.
Ø	($0.2)	($3.0)	Increase in office and administration expenses was primarily due to higher salaries, wages and corporate recharges on increased headcount.
Ø	($1.8)	$8.5	Increase in foreign exchange gain for the year was mainly due to the 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 quarter ended March 31, 2012. Reduction in foreign exchange gain for the quarter was a result of the weakening of PGK against USD in fourth quarter of 2012 (foreign exchange rate decreased from 0.4805 to 0.4755) compared to fourth quarter of 2011 (foreign exchange rate increased from 0.4465 to 0.4665).
Ø	$0.3	($1.1)	Increase in depreciation and amortization for the year was mainly due to the depreciation charge for capital additions, which primarily related to office refurbishment and upgrade projects across various terminals and depots.
Ø	$0.8	$1.5	Decrease in interest expense for the year was mainly due to the repayment of intercompany loans and lower utilization of working capital facilities during the year.
Ø	($2.5)	($8.6)	Increase in income tax expense mainly due to the higher profit before tax earned during the periods.

Management Discussion and Analysis   INTEROIL CORPORATION   23

CORPORATE – QUARTER AND YEAR IN REVIEW

Corporate – Operating results	Quarter ended December 31,						Year ended December 31,
($ thousands)	2012			2011			2012			2011
External sales		56			69			196			266
Inter-segment revenue - Sales		6,087			5,630			22,650			13,859
Inter-segment revenue - Recharges		18,838			4,585			41,905			39,503
Interest revenue		12,567			11,547			49,176			38,512
Other non-allocated revenue		4			-			4			(23	)
Total revenue		37,552			21,831			113,931			92,117
Cost of sales and operating expenses		(5,217	)		(5,050	)		(18,905	)		(11,421	)
Office and administration and other expenses		(18,138	)		(6,169	)		(52,383	)		(47,371	)
Derivative gain		-			307			11			(11	)
Foreign exchange (loss)/gain		(64	)		801			486			954
Loss on Flex LNG investment		-			(1,586	)		-			(3,420	)
EBITDA (1)		14,133			10,134			43,140			30,848
Depreciation and amortization		(683	)		(527	)		(2,370	)		(1,706	)
Interest expense		(1,601	)		(1,498	)		(6,185	)		(6,012	)
Profit before income taxes		11,849			8,109			34,585			23,130
Income tax expense		(1,330	)		(493	)		(1,498	)		(1,248	)
Net profit		10,519			7,616			33,087			21,882
Gross Margin (2)		926			649			3,941			2,704

(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 Year ended December 31, 2012 and 2011

The following analysis outlines the key movements, the net of which primarily explains the variance in the results between the quarters and years ended December 31, 2012 and 2011.

Quarterly Variance ($ millions)		Yearly Variance ($ millions)
	$2.9	$11.2	Net profit variance for the comparative period primarily due to:
Ø	$0.3	$1.2	Increase in external sales and inter-segment sales less cost of sales was mainly due to higher profit margin earned by shipping business during the financial periods.
Ø	$14.3	$2.4	Increase in inter-segment recharges for the year was mainly due to the following: - In March 2011, InterOil Corporate PNG Limited was incorporated to employ all corporate staff in PNG 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 based on an equitable basis. This entity began transacting in October 2012. The corporate costs incurred from January 2012 to September 2012 were captured within the Midstream - Refining segment and then recharged to other segments; and - Finalize and true up of full year recharges in the quarter ended December 31, 2012.
Ø	$1.0	$10.7	Higher interest income for both periods was due to an increase in inter-company loan balances.
Ø	($12.0)	($5.0)	Increase in office and administrative expense mainly due to the costs associated with corporate employees in PNG and the operation of the Napa Napa camp now being captured in the Corporate segment since October 1, 2012. These costs were previously captured within the Midstream - Refining segment.
Ø	$1.6	$3.4	Decrease in loss on available-for-sale investment was due to the impairment losses recognized in prior periods for the reduction in fair value of the FLEX LNG investment as of the period ends. The FLEX LNG investment is held as part of the framework agreements entered into with FLEX LNG and Samsung Heavy Industries in April 2011.
Ø	($0.9)	($0.3)	Increase in income tax expense was mainly due to higher profit before tax earned during the periods.

Management Discussion and Analysis   INTEROIL CORPORATION   24

CONSOLIDATION ADJUSTMENTS – QUARTER AND YEAR IN REVIEW

Consolidation adjustments – Operating results	Quarter ended December 31,						Year ended December 31,
($ thousands)	2012			2011			2012			2011
Inter-segment revenue - Sales		(175,329	)		(162,515	)		(673,677	)		(590,729	)
Inter-segment revenue - Recharges		(19,805	)		(7,410	)		(60,707	)		(48,344	)
Interest revenue (1)		(12,552	)		(11,502	)		(49,121	)		(38,010	)
Total revenue		(207,686	)		(181,427	)		(783,505	)		(677,083	)
Cost of sales and operating expenses (2)		175,622			162,721			671,786			592,527
Office and administration and other expenses (3)		19,865			7,427			60,930			48,541
EBITDA (4)		(12,199	)		(11,279	)		(50,789	)		(36,015	)
Depreciation and amortization (5)		31			32			130			130
Interest expense (1)		12,552			11,500			49,120			38,010
Profit/(loss) before income taxes		384			253			(1,539	)		2,125
Income tax expense		-			-			-			-
Net profit/(loss)		384			253			(1,539	)		2,125
Gross Margin (6)		293			206			(1,891	)		1,798

(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   25

Analysis of Consolidation Adjustments Comparing the Quarter and Year ended December 31, 2012 and 2011

The following table outlines the key movements, the net of which primarily explains the variance in the results between the quarters and years ended December 31, 2012 and 2011.

Quarterly Variance ($ millions)		Yearly Variance ($ millions)
	$0.1	($3.7)	Net profit/(loss) variance for the comparative period primarily due to:
Ø	$0.1	($3.7)	Variance in net income 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 December 31, 2012.

Organization	Facility		Balance outstanding  December 31, 2012			Effective interest rate			Maturity date
ANZ, BSP and BNP syndicated secured loan facility	$	100,000,000	$	100,000,000			6.81	%	November 2017
BNP working capital facility	$	240,000,000	$	94,290,479	(1)		2.67	%	See detail below	(4)
Westpac PGK working capital facility	$	43,245,000		-			-		November 2014
BSP PGK working capital facility	$	24,025,000		-			-		August 2013
Westpac secured loan	$	12,857,000	$	12,857,000			4.73	%	September 2015
2.75% convertible notes	$	70,000,000	$	70,000,000			7.91	%(3)	November 2015
Mitsui unsecured loan (2)	$	11,912,297	$	11,912,297			6.24	%	See detail below

^{(1) Excludes letters of credit totaling $139.5 million, which reduces the available borrowings under the facility to $6.2 million at December 31, 2012.}

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

^{(3) Effective rate after bifurcating the equity and debt components of the $70 million principal amount of 2.75% convertible senior notes due 2015.}

^{(4) In October 2012, the BNP Paribas working capital facility agreement with a maximum availability of $240,000,000 was amended so that the facility was made evergreen and the annual renewal requirement removed.}

Management Discussion and Analysis   INTEROIL CORPORATION   26

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. 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 over the fixed assets of the refinery. The balance outstanding under the loan facility as at December 31, 2012 was $100.0 million. The interest rate on the loan is equal to LIBOR plus 6.5%. During the year ended December 31, 2012, the weighted average interest rate under the facility was 6.81%.

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. As at December 31, 2012, we have two installment payments of $8.0 million each due for payment on this secured loan on May 9, 2013 and November 9, 2013. A cash restricted balance of $ 11.3 million was held on deposit as at December 31, 2012 to secure our principal installment due on May 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 Paribas, the total facility is split into two components, Facility 1 and Facility 2, which are renewable annually and were renewed in February 2012 for another year. 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. At December 31, 2012, Facility 1 had a limit of $190.0 million (after a temporary reallocation of $10.0 million limit from Facility 2 to Facility 1) 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, 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 (reduced to $50.0 million at December 31, 2012 due to temporary reallocation to Facility 1) and can be used for partly cash-secured short term advances and for discounting of any monetary receivables acceptable to BNP Paribas 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 December 31, 2012, $6.2 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 2.67% for the year ended December 31, 2012 (compared with 2.96% for the same period of 2011), after including the reduction in interest due to the deposit amounts (restricted cash) maintained as security.

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 December 31, 2012 was PGK 140.0 million (approximately $66.6 million).

The Westpac facility limit is PGK 90.0 million (approximately $42.8 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 $4.8 million). The BSP facility limit is PGK 50.0 million (approximately $23.8 million), and was renewed in November 2012 for another year ending in August 2013. As at December 31, 2012, none of this combined facility had been drawn down.

Management Discussion and Analysis   INTEROIL CORPORATION   27

The weighted average interest rate under the Westpac facility was 10.0% for the year ended December 31, 2012, and the weighted average interest rate under the BSP facility was 9.95% for the year ended December 31, 2012.

Westpac Secured Loan (Downstream)

During the quarter ended March 31, 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 December 31, 2012 was $12.9 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 Paribas 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.

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 Condensate Stripping Project Joint Venture with Mitsui for 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.

The portion of funding that relates to Mitsui’s share of the Condensate Stripping Project as at December 31, 2012, 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 is 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 year ended December 31, 2012 the weighted average interest rate was 6.24%.

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.

Management Discussion and Analysis   INTEROIL CORPORATION   28

Cash calls are made on IPI holders, PNGDV and Pac LNG (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.

The preliminary financing agreement entered into with Mitsui provides for funding by Mitsui of all the costs relating to the Condensate Stripping Project. 50% of the funding is for Mitsui’s share of the project and the other 50% is funding by Mitsui of our share of the project. There were $3.58 million contributions from Mitsui during the year ended December 31, 2012 for either Mitsui’s or our share, therefore leaving the total contributions at $25.4 million. In the event that a positive FID is not reached or made within the time specified, we will be required to refund all of Mitsui’s contributions (i.e. for our share and Mitsui’s) within a specified period.

On April 18, 2012, we signed a binding HOA 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. On July 27, 2012, we executed a Farm-In Agreement with PRE relating to the Triceratops structure and the participating interest in the PPL 237 license materially in line with the HOA signed on April 18, 2012. On November 29, 2012, we executed the PRE JVOA and related documents associated with the Farm-In Agreement. PRE has the option to terminate the Farm-In Agreement at various stages of the work program and to be reimbursed up to $96.0 million of the $116.0 million initial cash payment (which does not include carried costs) out of future upstream production proceeds.

As at December 31, 2012, PRE has paid $40.0 million of the staged cash payments. The first $20.0 million was paid in accordance with the HOA and became non-refundable on execution of the Farm-In Agreement. The second cash payment of $20.0 million was paid in accordance with the Farm-In Agreement under the advance payment facility. Subsequent to year end, in January 2013 a further $20.0 million of the staged cash payment was received from PRE.

Summary of Cash Flows

	Year ended December 31,
($ thousands)	2012			2011			2010
				(revised)			(revised)
Net cash inflows/(outflows) from:
Operations		(36,029	)		44,235			(30,543	)
Investing		(169,713	)		(185,805	)		(94,176	)
Financing		185,698			(27,165	)		311,846
Net cash movement		(20,044	)		(168,735	)		187,127
Opening cash		68,846			233,577			46,450
Exchange gains on cash and cash equivalents		1,058			4,005			-
Closing cash		49,860			68,846			233,577

Revision to Consolidated Statement of Cash Flows of 2011 and 2010

Under Canadian GAAP, we had adopted the accounting policy of treating oil and gas properties expensed (exploration costs, excluding exploration impairment) as an investing activity in the statement of cash flows as they represented the extent to which expenditures have been made for resources intended to generate future income and cash flows. We continued to treat these expenses as an investing activity in its first and subsequent sets of IFRS financial statements, which was not in line with the specific IFRIC clarification to IAS 7, effective January 1, 2010, that confirmed that only expenditures that result in a recognized asset in the balance sheet being eligible for classification as investing activities. The revision has no impact on basic or diluted earnings per share and is a Cash Flow Statement reclassification only.

Management Discussion and Analysis   INTEROIL CORPORATION   29

Refer to Note 3 of the audited annual consolidated financial statements for the year ended December 31, 2012 for further information in relation to the revisions made to the Consolidated Statement of Cash Flows for the years ended December 31, 2011 and 2010 to reflect the correct classification of exploration costs. In addition, the note also details the revisions made to the interim Consolidated Statement of Cash Flows in our first and subsequent IFRS quarterly financial statements for the periods three months ended March 31, 2012 and 2011, six months and quarters ended June 30, 2012 and 2011, and nine months and quarters ended September 30, 2012 and 2011.

Analysis of Cash Flows (Used In)/Generated From Operating Activities Comparing the Years ended December 31, 2012 and 2011

The following table outlines the key variances in the cash (outflows)/inflows from operating activities between the years ended December 31, 2012 and 2011:

Yearly variance ($ millions)
	($80.3)	Variance for the comparative period primarily due to:
Ø	($48.9)	Increase in cash employed by operations prior to changes in operating working capital for the year, mainly due to the decrease in net profit from operations adjusted for higher future income tax benefits, lower stock compensation and decrease in loss on the FLEX LNG investment.
Ø	($31.4)	The movements in cash generated by operations relating to changes in operating working capital were due primarily to a $51.4 million decrease in the movement of accounts payable and accrued liabilities for the year, a $21.6 million decrease in the movement of trade receivables, a $0.9 million increase in the movement of inventories due to timing of crude and export shipments, and a $0.8 million increase in the movement of other current assets and prepaid expenses.

Analysis of Cash Flows Used In Investing Activities Comparing the Years ended December 31, 2012 and 2011

The following table outlines the key variances in the cash (outflows)/inflows from investing activities between the years ended December 31, 2012 and 2011:

Yearly variance
($ millions)
	$16.1	Variance for the comparative period primarily due to:
Ø	($67.7)	Higher cash outflows on exploration and development program expenditures related to drilling costs associated with the Triceratops-2 and Antelope-3 appraisal wells.
Ø	$2.7	Higher cash calls and related inflows from IPI holders and PNGDV relating to the Triceratops-2 well. There were minimal cash calls received in the same period of 2011 due to activity being focused on seismic activities, for which no contribution is required, rather than appraisal drilling and subsequent work program activities.
Ø	$5.4	Higher expenditure on plant and equipment in the Downstream and Refinery segments in the prior year. The expenditures in the prior year were mainly associated with refurbishment of retail sites, tank upgrades and camp and office refurbishments.
Ø	$20.0	Receipt of $20.0 million initial staged cash payment received from PRE for the sell down of a net 10.0% (12.9% gross) participating interest in PPL 237 in accordance with HOA.
Ø	$23.7	Maturity of short term PGK Treasury bills in 2012 as compared with the investment in the PGK Treasury Bills in 2011.
Ø	$7.5	Acquisition of FLEX LNG shares net transaction costs in prior year.
Ø	($17.8)	Higher cash outflows due to increase in our cash restricted balance held under BNP working capital facility and ANZ, BSP and BNP syndicated secured loan facility as at December 31, 2012.
Ø	$42.3	Movements in non-operating working capital relating to accounts receivable, accounts payable and accruals in our Upstream and Midstream Liquefaction operations.

Management Discussion and Analysis   INTEROIL CORPORATION   30

Analysis of Cash Flows Generated From/(Used In) Financing Activities Comparing the Years ended December 31, 2012 and 2011

The following table outlines the key variances in the cash inflows/(outflows) from financing activities between years ended December 31, 2012 and 2011:

Yearly variance ($ millions)
	$212.9	Variance for the comparative periods primarily due to:
Ø	($26.5)	Higher repayment of OPIC loan as full repayment of the facility was made in November 2012.
Ø	($6.3)	Lower funding received from Mitsui relating to the Condensate Stripping Project.
Ø	$12.9	Movement in Westpac secured loan was attributable to the $15.0 million drawdown of loan made in first quarter of 2012 and $2.1 million semi-annual principal loan repayment to Westpac in third quarter of 2012.
Ø	($2.3)	Proceeds received from Pac LNG in year 2011 for its share of costs incurred in developing the LNG Project.
Ø	$20.0	Receipt of $20.0 million second staged cash payment under advance payment facility from PRE for the sell down of a net 10.0% (12.9% gross) participating interest in PPL 237.
Ø	$112.6	Movement in utilization of the BNP, Westpac and BSP working capital facilities is due to movement in working capital requirements.
Ø	$95.9	Movement in ANZ, BSP and BNP syndicated secured loan facility was attributable to the $100.0 million drawdown of loan made in November 2012, partially offset by the transaction costs of $4.1 million.
Ø	$6.6	Increase in receipts of cash from the exercise of stock options.

Capital Expenditures

Upstream Capital Expenditures

Capital expenditures for our Upstream segment in Papua New Guinea for the year ended December 31, 2012 were $147.8 million, compared with $107.6 million during the same period of 2011.

Management Discussion and Analysis   INTEROIL CORPORATION   31

The following table outlines the key expenditures in the year ended December 31, 2012:

Yearly ($ millions)
	$147.8	Expenditures in the year ended December 31, 2012 primarily due to:
Ø	$26.3	Drilling and testing costs for the Triceratops-2 well (net of the $11.5 million allocation of Triceratops share of HOA cash payment received from PRE, net of Pac LNG's interest, commission and stamp duty, against the cost base of the Triceratops field included within oil and gas properties on the balance sheet upon the execution of Farm-in Agreement).
Ø	$26.4	Project management teams’ costs and sub-contractors costs incurred for LNG Project, including costs incurred for pipeline works, which mainly consists of work done by Cronus 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	$26.4	Costs for works at Hou Creek, which includes the construction of a road and a complex in the north of the Elk and Antelope fields. The complex includes facilities such as wharf, camp, warehouse and related earth works. 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	$25.0	Costs incurred for Antelope-3 well site preparation and spud works.
Ø	$9.4	Costs incurred for Elk-3 well site preparation, spud works and drilling works.
Ø	$19.5	Costs incurred for Herd Base to Antelope field road construction.
Ø	$2.5	Costs incurred for the purchase of Rig#3.
Ø	$12.3	Other expenditures, including equipment purchases and drilling inventory.

Midstream – Refining Capital Expenditures

Capital expenditures totaled $12.2 million in our Midstream - Refining segment for the year ended December 31, 2012, mainly associated with camp, office building works and tank works.

Midstream – Liquefaction Capital Expenditures

Capital expenditures for our LNG segment in Papua New Guinea for the year ended December 31, 2012 were $10.2 million, mainly associated with project management teams’ costs and sub-contractors costs incurred for the LNG Project.

Downstream Capital Expenditures

Capital expenditures for the Downstream segment totaled $12.7 million for the year ended December 31, 2012. These expenditures mainly related to a number of upgrade projects across various terminals and depots, and also included amounts spent on our first retail site.

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.

Management Discussion and Analysis   INTEROIL CORPORATION   32

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 PNG. 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 $125.0 million IPI Agreement of 2005 to drill eight exploration wells. We have drilled four wells to date. As at December 31, 2012, we are committed under the terms of our exploration licenses or PPL’s to spend a further $49.3 million through 2014. As at December 31, 2012, management estimates that satisfying these license commitments with the expenditure of $49.3 million would also satisfy our commitments to the IPI investors in relation to drilling the final four wells and satisfy the commitments in relation to the IPI Agreement. The actual gross costs of drilling final exploration four wells in relation to the IPI Agreement may cost more than what is required to satisfy our license commitments.

In addition, the terms of 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 $268.0 million on PRL 15 which includes seismic, Herd Base/Hou Creek wharf and camps, roads, FEED for wells, gas gathering, condensate stripping, and pipelines. $56.0 million of the expenditures to date relates to the $73.0 million commitment. Expenditure on the drilling of the Elk-3 well will, in addition to a second well prior to license renewal date in 2014, 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 enable the availability of 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, LNG Project and exploration licenses. The solicitation process is now under way and we believe if successful, it will provide a further source of funds for exploration and development activities. No assurances can be given that we will be able to attract strategic partners on terms acceptable to us.

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

Midstream - Refining

We believe that we will have sufficient funds from our operating cash flows to pay our estimated capital expenditures associated with our Midstream Refining segment in 2013. We also believe cash flows from operations will be sufficient to cover the costs of operating our refinery and the financing charges incurred under our crude import facility. Should there be long term deterioration in refining margins, our refinery may not generate sufficient cash flows to cover all of the interest and principal payments under our secured loan agreements. As a result, we may be required to raise additional capital and/or refinance these facilities in the future.

Management Discussion and Analysis   INTEROIL CORPORATION   33

Midstream - Liquefaction

Completion of the 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.

In September 2011, we retained Morgan Stanley & Company LLC, Macquarie Capital (USA) Inc. and UBS AG to help solicit and evaluate proposals from potential strategic partners to, amongst other things, obtain an interest in, operate and help finance the development of the LNG Project. We have received conforming and non-conforming bids for the LNG partnering and sell down of an interest in the Elk and Antelope fields that we believe would be accretive to shareholders. Final bids are due by February 28, 2013, following which we expect to choose a partner in March 2013. The end result of the partnering process is expected to fully satisfy all the terms of the 2009 LNG Project Agreement. No assurances can be given that we will be able to attract a strategic partner on terms acceptable to us, and we cannot advise at this time as to how such an agreement will affect our current LNG Project plans or whether such a partner will be acceptable to the PNG government.

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 business 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 audited consolidated financial statements for year ended December 31, 2012 and the notes thereto:

	Payments Due by Period
Contractual obligations  ($ thousands)	Total		Less than 1 year		1 - 2 years		2 - 3 years		3 - 4 years		4 - 5 years		More than 5 years
Petroleum prospecting and retention licenses (a)		69,952		44,702		25,250		-		-		-		-
Secured and unsecured loans		159,779		39,545		27,414		31,200		30,810		30,810		-
2.75% Convertible notes obligations		75,615		1,925		1,925		71,765		-		-		-
Indirect participation interest - PNGDV		1,384		1,384		-		-		-		-		-
Total		306,730		87,556		54,589		102,965		30,810		30,810		-

(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 $49.3 million as a condition of renewal of our petroleum prospecting licenses through 2014 under our exploration licenses. As at December 31, 2012, management estimates that satisfying this license commitment with the expenditure of $49.3 million would also satisfy our commitments to the IPI investors in relation to drilling the final four wells and satisfy the commitments in relation to the IPI agreement. In addition, the terms of grant of PRL 15, requires us to spend a further $20.7 million on the development of the Elk and Antelope fields by the end of 2014.

Management Discussion and Analysis   INTEROIL CORPORATION   34

The following table contains information on payments required to meet our operating lease commitments. It should be read in conjunction with our audited financial statements for the year ended December 31, 2012 and the notes thereto:

	Year ended December 31,
($ thousands)	2012		2011		2010
Not later than 1 year		16,252		6,983		6,257
Later than 1 year and not later than 5 years		8,006		6,560		8,558
Later than 5 years		3,123		2,958		458
Total		27,381		16,501		15,273

Off Balance Sheet Arrangements

Neither during the year ended, nor as at December 31, 2012, did we have any off balance sheet arrangements or any relationships with unconsolidated entities or financial partnerships.

Transactions with Related Parties

During the year ended December 31, 2012, we did not have any transactions with any related parties.

Share Capital

Our authorized share capital consists of an unlimited number of common shares and unlimited number of preferred shares, of which 1,035,554 series A preferred shares are authorized (none of which are outstanding). As of December 31, 2012, we had 48,607,398 common shares (50,899,454 common shares on a fully diluted basis) and no preferred shares issued and outstanding. The potential dilutive instruments outstanding as at December 31, 2012 included employee stock options and restricted stock in respect of 1,219,551 common shares, IPI conversion rights to 140,480 common shares and 732,025 common shares relating to the $70.0 million principal amount 2.75% convertible senior notes due November 15, 2015.

Derivative Instruments

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

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

The derivative instruments which we generally use are the 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 the 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 ICE to hedge our crude costs.

Management Discussion and Analysis   INTEROIL CORPORATION   35

At December 31, 2012, we had a net receivable of $0.2 million (December 31, 2011 – receivable of $0.6 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 December 31, 2012 and will be settled in future.

INDUSTRY TRENDS AND KEY EVENTS

Competitive Environment and Regulated Pricing

We are currently the sole refiner of hydrocarbons in Papua New Guinea although there is no legal restraint upon other refineries being established. The PNG Government has agreed to ensure that all domestic distributors purchase their refined petroleum products from our refinery, or any other refinery which is constructed in Papua New Guinea, at an Import Parity Price (“IPP”). The IPP is monitored by the ICCC. In general, the IPP is the price that would be paid in Papua New Guinea for a refined product being imported. For all price controlled products (diesel, unleaded petrol, kerosene and aviation fuel) produced and sold locally in Papua New Guinea, the IPP is calculated by adding the costs that would typically be incurred to import such product to MOPS, which is the benchmark price for refined products in the region in which we operate.

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

We are also a significant participant in the retail and wholesale distribution business in Papua New Guinea. The ICCC regulates the maximum prices and margins that may be charged by the wholesale and retail hydrocarbon distribution industry in Papua New Guinea. Margins were last reviewed by the ICCC in quarter ended December 31, 2012 and will be further reviewed in quarter ended December 31, 2013. We and our competitors may charge less than the maximum margin set by the ICCC in order to maintain competitiveness.

Our main competitor in the wholesale and retail distribution business in Papua New Guinea is ExxonMobil. We also compete with smaller local distributors of petroleum products. Our competitors source small quantities from our refinery from both the refinery gantry for the Port Moresby market and by tanker vessel for the markets outside Port Moresby. Our major competitive advantage is the large widespread distribution network we maintain with adequate storage capacity that services most areas of PNG. We also believe that our commitment to the distribution business in Papua New Guinea at a time when major-integrated oil and gas companies exited the Papua New Guinea fuel distribution market provides us with a competitive advantage. However, major-integrated oil and gas companies such as ExxonMobil have greater resources than we do and could if they decided to do so, expand much more rapidly in this market than we can.

Management Discussion and Analysis   INTEROIL CORPORATION   36

Our proposed LNG Project faces competition, including competing liquefaction facilities and related infrastructure, from competitors with far greater resources, including major international energy companies. Many competing companies have secured access to, or are pursuing development or acquisition of, liquefaction facilities to serve the same markets we intend to target. In addition, competitors have developed or reopened additional liquefaction facilities in other international markets, which may also compete with our LNG Project. Almost all of these competitors have longer operating histories, more development experience, greater name recognition, larger staffs and substantially greater financial, technical and marketing resources and access to natural gas and LNG supplies than we do. The superior resources that these competitors have available for deployment could allow them to compete successfully against our LNG businesses, which could have a material adverse effect on our business, results of operations, financial condition, liquidity and prospects.

Financing Arrangements

We continue to monitor liquidity risk by setting of acceptable gearing levels and ensuring they are monitored. Our aim is to maintain our debt-to-capital ratio, or gearing levels, (debt divided by (shareholders’ equity plus debt)) at 50% or less. This was achieved throughout 2012 and 2011. Gearing levels were 19% in December 2012, 12% in December 2011 and 13% in December 2010.

On November 10, 2010, we completed concurrent public offerings of $70.0 million aggregate principal amount of 2.75% convertible senior notes due 2015 and 2,800,000 common shares at a price of $75.00 per share for proceeds of $210.0 million, raising gross proceeds of $280.0 million from the combined offerings.

During the year ended December 31, 2012, we entered into a five year amortizing $100 million syndicated secured term loan facility with BNP, BSP and ANZ. The borrowings under the facility were used to repay all outstanding amounts under the term loan granted by OPIC, and the remaining funds will be used for general corporate purposes.

For details of other financial arrangements in place, see “Liquidity and Capital Resources – Summary of Debt Facilities”.

We had cash, cash equivalents and cash restricted of $98.9 million as at December 31, 2012, of which $49.0 million was restricted (as governed by BNP working capital facility utilization requirements and ANZ, BSP and BNP syndicated secured loan facility). With regard to our cash and cash equivalents, we invest in bankers acceptances and money market instruments with major financial institutions that we believe are creditworthy. We also had $6.2 million of the combined BNP working capital facility available for use in our Midstream – Refining operations, and $66.6 million of the Westpac/BSP combined working capital facility available for use in our Downstream operations.

Crude Prices

Crude prices fluctuated throughout 2012, with the price of Dated Brent crude oil (as quoted by Platts) starting the year at $111 per barrel and closing the year at $110 per barrel. The average price for Dated Brent for 2012 was $112 per barrel compared with $111 per barrel for Dated Brent for 2011 and $81 per barrel for Dated Brent for 2010. Dated Brent peaked in March 2012 at $128 per barrel and was at its lowest in June 2012 at $88 per barrel.

At year end, we had $6.2 million of the combined BNP working capital facility available for use in our Midstream – Refining operations, and approximately $66.6 million of the Westpac/BSP combined working capital facility available for use in our Downstream operations. Any increase in prices will have an impact on the utilization of our working capital facilities, and related interest and financing charges on the utilized amounts.

Any volatility of crude prices means that we face significant timing and margin risk on our crude cargos. A significant portion of this timing and margin risk is managed by us through short and long term hedges. There was a net receivable of $0.2 million relating to open contracts to sell gasoil crack swaps and Naphtha crack swaps and buy/sell Dated Brent swaps for which hedge accounting has not been applied.

Refining Margin

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

Management Discussion and Analysis   INTEROIL CORPORATION   37

Distillate margins to Dated Brent strengthened during 2012 compared with historical levels due to increasing demand. Naphtha crack spreads were negative for all of 2012, which negatively affects our gross margin for the period.

Domestic Demand

Sales results for our refinery for 2012 indicate that Papua New Guinea’s domestic demand for middle distillates (which includes diesel and jet fuels) from the refinery has increased by approximately 10.8% compared with 2011.  However, the total volume of all products sold by us was 8.5 million barrels for fiscal year 2012 compared with 7.2 million barrels in 2011 and 7.2 million barrels in 2010.  Total volume of PNG domestic sales only for 2012 was 5.3 million barrels as compared with 4.6 million barrels in 2011 and 4.3 million barrels in 2010.

The refinery on average sold 13,978 barrels per day of refined petroleum products to the domestic market during fiscal year 2011 compared with 12,649 barrels per day in 2011 and 11,780 barrels per day in 2010. 

Interest Rates

The LIBOR USD overnight rate is the benchmark floating rate used in our midstream working capital facility and therefore accounts for a significant proportion of our interest rate exposure. The LIBOR USD overnight rate remained constant between 0.15% and 0.20% for the majority of 2012. Any rate increases would add additional cost to financing our crude cargoes and vice versa as our BNP Paribas working capital facility is linked to LIBOR rates. See “Liquidity and Capital Resources – Summary of Debt Facilities”.

Exchange Rates

Changes in the PGK to USD exchange rate can affect our Midstream Refinery results as there is a timing difference between the foreign exchange rates utilized when setting the monthly IPP, which is set in PGK, and the foreign exchange rate used to convert the subsequent receipt of PGK proceeds to USD to repay our crude cargo borrowings. The PGK has weakened against the USD in the second half of the financial year ended December 31, 2012 (from 0.4840 to 0.4755).

Changes in the AUD and SGD to USD exchange rate can affect our Corporate results as the expenses of the Corporate offices in Australia and Singapore are incurred in the respective local currencies. The AUD and SGD exposures are minimal currently as funds are transferred to AUD and SGD from USD as required. No material balances are held in AUD or SGD. However, we are exposed to translation risks resulting from AUD and SGD fluctuations as in country costs are being incurred in AUD and SGD and reporting for those costs being in USD. We have entered into AUD to USD foreign currency forward contracts to manage the foreign exchange risk in relation to the expenses to be incurred in AUD.

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.

Management Discussion and Analysis   INTEROIL CORPORATION   38

CRITICAL ACCOUNTING ESTIMATES

The preparation of financial statements in accordance with IFRS requires our management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates. The effect of changes in estimates on future periods have not been disclosed in the consolidated financial statements as estimating it is impracticable. The following accounting policies involve estimates that are considered critical due to the level of sensitivity and judgment involved, as well as the impact on our consolidated financial position and results of operations. The information about our critical accounting estimates should be read in conjunction with Note 2 of the notes to our consolidated financial statements for the year ended December 31, 2012, available at www.sedar.com which summarizes our significant accounting policies.

Income Taxes

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

Oil and Gas Properties

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

Asset Retirement Obligations

A liability is recognized for future legal or constructive retirement obligations associated with the Company’s property, plant and equipment. The amount recognized is the net present value of the estimated costs of future dismantlement, site restoration and abandonment of properties based upon current regulations and economic circumstances at period end. During the quarter ended June 30, 2011, Management received the results of an independent assessment of the potential asset retirement obligations of the refinery at the time of decommissioning and a provision of $4,100,735 was recognized for the present value of the estimated expenditure required to complete this obligation. These costs have been capitalized as part of the cost of the refinery and are depreciated over the life of the asset. The provision will be accreted over the remaining useful life of the refinery to bring the provision to the estimated expenditure required at the time of decommissioning. The asset retirement obligation as at December 31, 2012 was $4,978,334. If we adjust the estimates in future periods, it may result in increased capital expenditures and a corresponding increase in liabilities.

Management Discussion and Analysis   INTEROIL CORPORATION   39

Environmental Remediation

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

Impairment of Long-Lived Assets

We are required to review the carrying value of all property, plant and equipment, including the carrying value of oil and gas assets, and goodwill for potential impairment. We test long-lived assets for recoverability whenever events or changes in circumstances indicate that its carrying amount may not be recoverable by the future discounted cash flows. Due to the significant subjectivity of the assumptions used to test for recoverability and to determine fair value, changes in market conditions could result in significant impairment charges in the future, thus affecting our earnings. Our impairment evaluations are based on assumptions that are consistent with our business plans.

Legal and Other Contingent Matters

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

NEW ACCOUNTING STANDARDS

New accounting standards not yet applicable as at December 31, 2012

The following new standards have been issued but are not yet effective for the financial year beginning January 1, 2012 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. The Company is yet to assess IFRS 9’s full impact, but do not expect any material changes due to this standard. The Company has not yet decided to early adopt IFRS 9.

- IFRS 10 'Consolidated Financial Statements' (effective from January 1, 2013): This builds on existing principles by identifying the concept of control as the determining factor in whether an entity should be included within the consolidated financial statements. The standard provides additional guidance to assist in determining control where this is difficult to assess. This new standard will have no impact on the entities that we currently consolidate as subsidiaries.

- IFRS 11 'Joint Arrangements' (effective from January 1, 2013): This provides for a more realistic reflection of joint arrangements by focusing on the rights and obligations of the arrangement, rather than its legal form. There are two types of joint arrangements: joint operations and joint ventures. Joint operations arise where a joint operator has rights to the assets and obligations relating to the arrangement and hence accounts for its interest in assets, liabilities, revenue and expenses. Joint ventures arise where the joint operator has rights to the net assets of the arrangement and hence equity accounts for its interest. Proportional consolidation of joint ventures is no longer allowed. Under IFRS 11, the LNG Project will be classified as a joint venture and we will therefore equity account for its interest in the LNG Project as compared to the current treatment of proportional consolidation. We will reassess the impact of this standard taking into consideration the final outcome of the ongoing sell down transaction process in relation to the Elk and Antelope fields.

Management Discussion and Analysis   INTEROIL CORPORATION   40

- IFRS 12 'Disclosure of Interests in Other Entities' (effective from January 1, 2013): This is a new standard on disclosure requirements for all forms of interests in other entities, including joint arrangements, associates, special purpose vehicles and other off balance sheet vehicles. As a result of this standard, we will have increased disclosure around the LNG Project joint venture.

- IFRS 13 ‘Fair Value Measurement’ (effective from January 1, 2013): This aims to improve consistency and reduce complexity by providing a precise definition of fair value and a single source of fair value measurement and disclosure requirements for use across IFRSs. As a result of this standard, there may be some additional disclosure requirements in our financial statements.

- IAS 27 ‘Separate Financial Statements’ (effective from January 1, 2013): This includes the provisions on separate financial statements that are left after the control provisions of IAS 27 have been included in the new IFRS 10. This new standard will have no impact on our financial statements.

- IAS 28 ‘Investments in Associates and Joint Ventures’ (effective from January 1, 2013): This now includes the requirements for joint ventures, as well as associates, to be equity accounted following the issue of IFRS 11. As a result of the LNG Project being classified as a joint venture under IFRS 11, we will have to equity account for its interest in the LNG Project in accordance with IAS 28. We will reassess the impact of this standard taking into consideration the final outcome of the ongoing sell down process in relation to the Elk and Antelope fields.

Management Discussion and Analysis   INTEROIL CORPORATION   41

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	Year ended December 31,
($ thousands)	2012			2011			2010
Midstream – Refining		1,095,925			939,278			674,137
Downstream		862,958			743,860			504,786
Corporate		22,846			14,125			402
Consolidation Entries		(673,677	)		(590,729	)		(376,951	)
Sales and operating revenues		1,308,052			1,106,534			802,374
Midstream – Refining		(1,071,852	)		(897,825	)		(605,603	)
Downstream		(800,217	)		(704,213	)		(470,772	)
Corporate (1)		(18,905	)		(11,421	)		-
Consolidation Entries		671,786			592,527			374,818
Cost of sales and operating expenses		(1,219,188	)		(1,020,932	)		(701,557	)
Midstream – Refining		24,073			41,453			68,534
Downstream		62,741			39,647			34,014
Corporate (1)		3,941			2,704			402
Consolidation Entries		(1,891	)		1,798			(2,133	)
Gross Margin		88,864			85,602			100,817

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

EBITDA represents our net income/(loss) plus total interest expense (excluding amortization of debt issuance costs), income tax expense, depreciation and amortization expense. EBITDA is used by us to analyze operating performance. EBITDA does not have a standardized meaning prescribed by GAAP (i.e. IFRS) and, therefore, may not be comparable with the calculation of similar measures for other companies. The items excluded from EBITDA are significant in assessing our operating results. Therefore, EBITDA should not be considered in isolation or as an alternative to net earnings, operating profit, net cash provided from operating activities and other measures of financial performance prepared in accordance with IFRS. Further, EBITDA is not a measure of cash flow under IFRS and should not be considered as such.

Management Discussion and Analysis   INTEROIL CORPORATION   42

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

Quarters ended	2012												2011
($ thousands)	Dec-31			Sep-30			Jun-30			Mar-31			Dec-31			Sep-30			Jun-30			Mar-31
Upstream		(873	)		956			(5,730	)		(6,374	)		665			(6,169	)		593			(10,957	)
Midstream – Refining		12,370			13,417			(42,647	)		18,933			2,604			3,461			27,967			26,632
Midstream – Liquefaction		192			11			676			(1,406	)		(4,123	)		(3,602	)		(4,035	)		(2,375	)
Downstream		12,258			9,275			11,102			21,414			6,808			3,570			5,777			8,744
Corporate		14,133			9,841			9,975			9,188			10,134			1,548			13,940			5,223
Consolidation Entries		(12,199	)		(14,503	)		(9,871	)		(14,214	)		(11,280	)		(10,263	)		(5,270	)		(9,200	)
Earnings before interest, taxes, depreciation and amortization		25,881			18,997			(36,495	)		27,541			4,808			(11,455	)		38,972			18,067
Subtract:
Upstream		(11,734	)		(11,438	)		(10,517	)		(9,408	)		(8,712	)		(7,806	)		(7,142	)		(6,352	)
Midstream – Refining		(11,390	)		(1,654	)		(2,011	)		(2,771	)		(3,285	)		(2,494	)		(2,211	)		(1,675	)
Midstream – Liquefaction		(586	)		(584	)		(579	)		(559	)		(445	)		(372	)		(268	)		(223	)
Downstream		(337	)		(394	)		(909	)		(1,233	)		(1,170	)		(1,233	)		(1,116	)		(826	)
Corporate		(1,601	)		(1,540	)		(1,535	)		(1,510	)		(1,498	)		(1,477	)		(1,641	)		(1,395	)
Consolidation Entries		12,552			12,482			12,044			12,045			11,500			10,041			8,894			7,572
Interest expense		(13,096	)		(3,128	)		(3,507	)		(3,436	)		(3,610	)		(3,341	)		(3,484	)		(2,899	)
Upstream		-			-			-			-			-			-			-			-
Midstream – Refining		16,574			(3,484	)		14,580			(1,948	)		19,243			678			(5,677	)		(7,298	)
Midstream – Liquefaction		-			-			-			-			-			-			-			-
Downstream		(3,070	)		(1,791	)		(2,907	)		(5,746	)		(595	)		(297	)		(1,449	)		(2,623	)
Corporate		(1,330	)		177			535			(880	)		(493	)		(195	)		(629	)		71
Consolidation Entries		-			-			-			-			-			-			-			-
Income taxes		12,174			(5,098	)		12,208			(8,574	)		18,155			186			(7,755	)		(9,850	)
Upstream		(474	)		(454	)		715			(1,462	)		(1,355	)		(1,105	)		(154	)		(641	)
Midstream – Refining		(4,153	)		(2,921	)		(2,891	)		(2,894	)		(2,878	)		(2,846	)		(2,764	)		(2,765	)
Midstream – Liquefaction		0			0			(4	)		(4	)		(6	)		(6	)		(6	)		(6	)
Downstream		(1,135	)		(1,464	)		(1,241	)		(1,240	)		(1,422	)		(894	)		(906	)		(804	)
Corporate		(683	)		(629	)		(530	)		(528	)		(527	)		(349	)		(395	)		(435	)
Consolidation Entries		31			33			32			33			32			32			32			32
Depreciation and amortisation		(6,414	)		(5,435	)		(3,919	)		(6,095	)		(6,156	)		(5,168	)		(4,193	)		(4,619	)
Upstream		(13,081	)		(10,936	)		(15,532	)		(17,244	)		(9,402	)		(15,080	)		(6,703	)		(17,949	)
Midstream – Refining		13,401			5,358			(32,969	)		11,320			15,684			(1,201	)		17,314			14,894
Midstream – Liquefaction		(394	)		(573	)		93			(1,969	)		(4,574	)		(3,980	)		(4,309	)		(2,604	)
Downstream		7,716			5,626			6,045			13,195			3,621			1,146			2,306			4,491
Corporate		10,519			7,849			8,445			6,270			7,616			(473	)		11,275			3,463
Consolidation Entries		384			(1,988	)		2,205			(2,136	)		252			(190	)		3,657			(1,596	)
Net profit/(loss) per segment		18,545			5,336			(31,713	)		9,436			13,197			(19,778	)		23,540			699

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.

Management Discussion and Analysis   INTEROIL CORPORATION   43

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 the December 31, 2012 for the foregoing purposes.

It should be noted that while the 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 three months ended December 31, 2012, 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.

GLOSSARY OF TERMS

“2012 Annual Information Form” means the Annual Information Form for the year ended December 31, 2012.

“AUD” means Australian dollars.

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

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

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

“Board” means the board of directors of InterOil.

“BSP” means Bank of South Pacific Limited.

“CDU” means crude distillation unit.

“CGR” means condensate to gas ratio.

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

“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.

Management Discussion and Analysis   INTEROIL CORPORATION   44

“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 or the joint venture formed to develop and operate the proposed condensate stripping facilities as the context requires.

“CSP JVOA” means the Joint Venture Operating Agreement entered into with Mitsui for the proposed condensate stripping facilities.

“CSP” or “Condensate Stripping Project” means the proposed condensate stripping facilities, including gathering and condensate pipeline, condensate storage and associated facilities being progressed in joint venture with Mitsui.

“DPE” means Department of Petroleum and Energy of Papua New Guinea.

“DST” means drill stem test.

“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”.

“EWC” means Energy World Corporation Limited., a company incorporated under the laws of Australia.

“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.

“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.

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

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

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

Management Discussion and Analysis   INTEROIL CORPORATION   45

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

“IPP” means import parity price. For each refined product produced and sold locally in Papua New Guinea, IPP is calculated under agreement with the State by adding the costs that would typically be incurred to import such product to an average posted price for such product in Singapore as reported by Platts. The costs added to the reported Platts price include freight costs, insurance costs, landing charges, losses incurred in the transportation of refined products, demurrage and taxes.

“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 Pac LNG and with other potential partners, including the State.

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

“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).

“Mmbtu” means one million British thermal units. One cubic foot of natural gas produces approximately 1,000 btus, so 1,000 cu.ft. of gas is comparable to 1 mmbtu.

“Mmscfpd” means million standard cubic feet of gas per day.

“MOPS” means Mean of Platts Singapore, which is the benchmark price for refined products in the region in which we operate.

“Mtpa” means million tonnes per annum.

“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.

“NEC” means National Executive Council of Papua New Guinea.

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

“NRV” means net realizable value.

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

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“Pac LNG” 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.

“PDL” means Petroleum Development License. The right granted by the State to develop a field for commercial production.

“Petromin” means Petromin PNG Holdings Limited, a company incorporated under the laws of Papua New Guinea by the State.

“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 Pac LNG.

“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.

“PRE JVOA” means the Joint Operating Agreement entered into with PRE for PPL 237 based on the provisions defined in the HOA and the Farm-In Agreement with PRE.

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

“SWC” means rotary side wall cores

“USD” means United States Dollars.

“VSP” means vertical seismic profile

“Westpac” means Westpac Bank PNG Limited.

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