EX-99.1 2 v439727_ex99-1.htm EXHIBIT 99.1

Exhibit 99.1

InterOil Corporation
Management
Discussion and Analysis

For the quarter ended March 31, 2016
May 13, 2016

TABLE OF CONTENTS

FORWARD-LOOKING STATEMENTS	2
ABBREVIATIONS AND EQUIVALENCIES	3
CONVERSION	4
OIL AND GAS DISCLOSURES	4
GLOSSARY OF TERMS	4
INTRODUCTION	6
BUSINESS STRATEGY	6
OPERATIONAL HIGHLIGHTS	7
SELECTED FINANCIAL INFORMATION AND HIGHLIGHTS	9
LIQUIDITY AND CAPITAL RESOURCES	13
RISK FACTORS	17
CRITICAL ACCOUNTING ESTIMATES	17
NEW ACCOUNTING STANDARDS	17
NON-GAAP MEASURES AND RECONCILIATION	17
PUBLIC SECURITIES FILINGS	18
DISCLOSURE CONTROLS AND PROCEDURES AND INTERNAL CONTROLS OVER FINANCIAL REPORTING	18

This MD&A (as defined herein) should be read in conjunction with our Condensed Consolidated Interim Financial Statements (as defined herein) and accompanying notes, our Consolidated Financial Statements (as defined herein) and our 2015 AIF (as defined herein). This MD&A was prepared by management and provides a review of our performance for the quarter ended March 31, 2016, and of our financial condition and future prospects.

Our financial statements and the financial information contained in this MD&A have been prepared in accordance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board applicable to the preparation of financial statements and are presented in United States dollars (“USD” or “$”) unless otherwise specified.

In this MD&A, references to “we,” “us,” “our,” “the Company,” and “InterOil” refer to InterOil Corporation or InterOil Corporation and its subsidiaries as the context requires. Information is presented in this MD&A as at March 31, 2016 and for the quarter ended March 31, 2016 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 and anticipated timing of our exploration and appraisal (including drilling plans) and other business activities and results therefrom; anticipated timing of certain well testing and resource certifications under the Total SSA (as defined herein); characteristics of our properties; construction and development of a proposed liquefaction plant and central processing facility in Papua New Guinea; the timing and cost of such construction and development; commercialization and monetization of any resources; whether sufficient resources will be established; the likelihood of successful exploration for gas and gas condensate or other hydrocarbons; cash flows from operations; sources of capital and its sufficiency; operating costs; contingent liabilities; environmental matters; and plans and objectives for future operations; and timing, maturity and amount of future capital and other expenditures and the ability to obtain requisite financing in the future.

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

our financial condition may be adversely affected if there are long term declines in oil and natural gas prices;

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

our limited sources of revenue;

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

inherent uncertainty of oil and gas exploration;

risks associated with the transition of our operatorship of PRL 15 to Total;

the difficulties with recruitment and retention of qualified personnel;

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

landowner claims and disruption;

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

the exploration and production businesses are competitive;

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

exposure to certain uninsured risks stemming from our operations;

contractual defaults;

weather conditions and unforeseen operating hazards;

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

general economic conditions, including further economic downturn, availability of credit and the decline in commodity prices, including hydrocarbon commodity prices;

risk of legal action against us;

law enforcement difficulties; and

dilution of our common shares.

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

Management Discussion and Analysis INTEROIL CORPORATION 2

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

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

Some of these assumptions and other risks and uncertainties that could cause actual results to differ materially from such forward-looking statements are more fully described under the heading “Risk Factors” in our 2015 AIF.

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

ABBREVIATIONS AND EQUIVALENCIES

Abbreviations

Crude Oil and Natural Gas Liquids		Natural Gas
bbl	one barrel equalling 34.972 Imperial gallons or 42 U.S. gallons	btu	British Thermal Units
bblspd	barrels per day	mcf	thousand standard cubic feet
boe⁽¹⁾	barrels of oil equivalent	mcfpd	thousand standard cubic feet per day
boepd	barrels of oil equivalent per day	MMbtu	million British Thermal Units
bpsd	barrels per stream day	MMbtupd	million British Thermal Units per day
Mboe	thousand barrels of oil equivalent	MMcf	million standard cubic feet
Mbbl	thousand barrels	MMcfpd	million standard cubic feet per day
MMbbls	million barrels	scfpd	standard cubic feet per day
MMboe	million barrels of oil equivalent	Tcfe⁽²⁾	trillion standard cubic feet equivalent
MMstb	millions of stock tank barrels	psi	pounds per square inch
WTI	West Texas Intermediate crude oil delivered at Cushing, Oklahoma
bscf	billion standard cubic feet

Note:

(1)

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

(2)

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

Management Discussion and Analysis INTEROIL CORPORATION 3

CONVERSION

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

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

OIL AND GAS DISCLOSURES

We are required to comply with the Canadian Securities Administrators’ NI 51-101 (as defined herein), which prescribes disclosure of oil and gas reserves and resources. As at December 31, 2015 and in accordance with NI 51-101, (i) GLJ Petroleum Consultants Ltd., an independent qualified reserve evaluator based in Calgary, Canada, has evaluated our resources data for the Elk and Antelope field and Triceratops field; and (ii) RISC Operations Pty Limited, an independent qualified reserve evaluator based in Perth, Australia has evaluated our resources data for the Raptor and Bobcat fields. These evaluations are summarized in our 2015 AIF available at www.sedar.com. We do not have any production or reserves, including proved reserves, as defined under NI 51-101 or as per the guidelines set by the SEC (as defined herein), as at March 31, 2016.

Well flow test results are not necessarily indicative of long-term performance or of ultimate recovery.

The SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved, possible and probable reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. We include in this MD&A information that the SEC’s guidelines generally prohibit U.S registrants from including in filings with the SEC.

GLOSSARY OF TERMS

“2015 AIF” means InterOil’s Annual Information Form for the year ended December 31, 2015.

“2015 MD&A” means Management’s Discussion and Analysis for the year ended December 31, 2015.

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

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

“BSP” means Bank of South Pacific Limited.

“CBA” means Commonwealth Bank of Australia.

Management Discussion and Analysis INTEROIL CORPORATION 4

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

“Condensed Consolidated Interim Financial Statements” means the unaudited condensed consolidated interim financial statements for the quarter ended March 31, 2016.

“Consolidated Financial Statements” means the audited consolidated financial statements for the years ended December 31, 2015, 2014 and 2013.

“Convertible Notes” means our 2.75% convertible senior notes which matured on November 15, 2015 and were fully paid on the same day.

“Credit Suisse” means Credit Suisse A.G.

“EBITDA” represents net income/(loss) plus total interest expense (excluding amortization of debt issuance costs), income tax expense, depreciation and amortization expense. EBITDA is a non-GAAP measure used to analyze operating performance. See “Non-GAAP Measures and Reconciliation”.

“Farm-In Agreement” means the Farm-In Agreement dated July 27, 2012 between us and PRE.

“GAAP” means Canadian generally accepted accounting principles.

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

“GCA” means Gaffney Cline & Associates, an independent qualified reserves evaluator.

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

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

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

“Macquarie” means Macquarie Group Limited.

“MD&A” means this Management’s Discussion and Analysis for the quarter ended March 31, 2016.

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

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

“Oil Search” means Oil Search Limited, a company incorporated in PNG, and its subsidiaries.

“Papua LNG Project” means the Elk-Antelope liquefied natural gas joint venture project operated by Total on behalf of the PRL 15 joint venture, which includes Total, Oil Search and us.

“PGK” means the kina, currency of PNG.

“PNGDV” means PNG Drilling Ventures Limited, an entity with which we entered into an amended and restated indirect participation agreement on May 1, 2006.

“PPL” means the Petroleum Prospecting License, an exploration tenement granted under the PNG Oil and Gas Act 1998.

Management Discussion and Analysis INTEROIL CORPORATION 5

“PRE” means Pacific Exploration and Production Corporation (formerly Pacific Rubiales Energy Corporation), a company incorporated under the laws of British Columbia, Canada.

“PRL” means the Petroleum Retention License, the tenement granted under the PNG Oil and Gas Act 1998 to allow the license holder to evaluate the commercial and technical options for the potential development of an oil and/or gas discovery.

“PRL 15 Joint Venture” means the current license holders in respect of PRL 15 and parties to the Elk/Antelope JVOA, dated September 26, 2013 (as amended and restated).

“Puma” means Puma Energy Pacific Holdings Pte Ltd.

“RISC” means RISC Operations Pty Limited, an independent qualified reserves evaluator.

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

“SocGen” means Société Generale Hong Kong branch.

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

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

“Total SSA” means the share purchase agreement under which Total acquired, through the purchase of all of the shares of SPI (200) Limited (now known as Total E&P PNG Limited), a wholly owned subsidiary, a gross 40.1275% interest in PRL 15.

“UBS” means UBS A.G.

“Westpac” means Westpac Bank PNG Limited.

INTRODUCTION

We are an independent oil and gas business with a sole focus on Papua New Guinea. Our assets include the Elk, Antelope, Triceratops, Raptor and Bobcat fields in the Gulf Province of Papua New Guinea, and exploration licenses covering about 16,000 square kilometers (about 4 million acres) in Papua New Guinea. We have our main offices in Singapore and Port Moresby. We are listed on the New York Stock Exchange and the Port Moresby Stock Exchange. At March 31, 2016, we had 117 full-time employees.

BUSINESS STRATEGY

Our strategy is to unlock significant value to shareholders by finding oil and gas safely and competitively; enabling its development through the right partnerships, funding and project development capability; co-developing these opportunities to producing assets whilst maintaining a material interest; and repeating this process to fully exploit our acreage position. The focus areas for our strategy are to:

Continue to develop as a prudent and responsible business operator;

Enable our discovered resources;

Maximize the value of our exploration assets; and

Position for long-term success.

Further details of our business strategy can be found under the heading “Business Strategy” in our 2015 AIF available at www.sedar.com.

Management Discussion and Analysis INTEROIL CORPORATION 6

OPERATIONAL HIGHLIGHTS

Summary of operational highlights

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

Airborne Field Survey

In January 2015, CGG Aviation (Australia) Pty Ltd began the acquisition of high resolution airborne gravity gradiometry over all of our PPLs and PRLs. As at March 31, 2016, we had completed 88% of the planned survey.

PRL 39 – Triceratops-3

In fourth quarter of 2015, we received notification from PRE of their intention to withdraw from further participation in PRL 39. There has been no change to the position disclosed in the 2015 MD&A. As disclosed in the 2015 MD&A, the Farm-In Agreement provides that following an effective withdrawal by PRE, we are required to refund to PRE $93.0 million in monthly installments commencing in the month subsequent to our receipt of any net cash proceeds from commercial sale of product from PRL 15 and the $93.0 million must be repaid in full within six years of receiving the withdrawal notification, or if our interest in PRL 15 becomes less than 30%. Following withdrawal of PRE, we also have a receivable of $29.7 million, which is refundable from Pacific LNG Operations Ltd, and other indirect participating interest holders, under the same terms as the amount refundable to PRE.

Subject to PRE withdrawing, our interest in the Triceratops discovery will be 78.1114%, and our interest in PRL 39 (excluding the Triceratops discovery) our interest will be 100% (94.25% assuming PNGDV elects to exercise their option to participate at their 5.75% interest election).

PRL 15 – Appraisal Program

During April 2015, the PRL 15 Joint Venture approved the drilling of a third appraisal well Antelope-6 to define the eastern flank of the reservoir. The Antelope-6 appraisal well was spudded by the PRL 15 Joint Venture on December 24, 2015. The well is located about 2km east-south-east of Antelope-3. On January 29 2016, we announced that the Antelope-6 appraisal well encountered top reservoir within expectations at approximately 2,076 meters (6,811 feet) true vertical depth sub-sea.

During February 2016, 9-5/8” liner was run to the Antelope-6 top reservoir, four cores were cut from the upper section of the reservoir and intermediate logs were run. The four cores were cut over an interval of 2,080 to 2,142 meters true vertical depth sub-sea and the well reached a depth within the reservoir section of 2,142 meters true vertical depth sub-sea. Formation evaluation of log data showed that 12 meters of dolomite was present in the drilled section with the remainder of the section being limestone of good reservoir quality. An intermediate, multi-rate flow test was conducted over an interval from 2,072 to 2,142 meters true vertical depth sub-sea to assess the deliverability of the matrix in the absence of major fractures. The test over the upper Kapau Limestone, completed in early March 2016, obtained a final stabilized flow rate of approximately 13 mmcfd over a 24 hour period, measured through a 40/64” choke.

Following the test, the well was drilled through the gas-water-contact to a total depth of 2,650 meters MDRT and a full suite of wireline logs run.

On January 21, 2016, the planned extended well test commenced at Antelope-5. The test was completed and the well flowed for a total of 343 hours producing a total volume of approximately 760 mmcf with a condensate gas ratio of 12.5 to 13.0 bbls/mmcf. Water rates were too low to be measured. The well was then shut-in for 16.75 days to record the subsequent pressure build-up. The majority of the stabilized flow occurred on a 48/64” choke at a rate of approximately 57 mmcfd. Downhole pressure gauges were successfully retrieved from both Antelope-5 and Antelope-1 (observation well) and extracted for analysis. Preliminary analysis confirmed the excellent reservoir quality and connectivity seen in the initial Antelope-5 production test conducted in mid-2015. The test has also provided further support to the volumetric estimates derived from the initial Antelope-5 production test. Further analysis to quantify nearby reservoir properties and volumetric estimates is ongoing.

Management Discussion and Analysis INTEROIL CORPORATION 7

The PRL15 Joint Venture is currently considering whether to drill the Antelope-7 appraisal well and a decision is expected to be made before the end of the second quarter of 2016. If the PRL 15 Joint Venture decides not to drill Antelope-7, the certification process would then be implemented with Antelope-6 being the last well in the appraisal program and we would expect the process to be completed by the end of September 2016. In the event the PRL15 Joint Venture decide to drill Antelope-7 the expected timing of the interim resource certification payment will change.

PRL15 License Extension Application

On May 27, 2015, the operator of the PRL15 Joint Venture, lodged an extension application with Department of Petroleum and Energy, in respect of PRL 15 which was due to expire on 29 November 2015 (the “Extension Application”). As part of the Extension Application, the PRL 15 Joint Venture proposed new work programs and commitments for the extension term.

The Extension Application is still being considered. Pursuant to section 45(10) of the PNG Oil and Gas Act 1998, PRL 15 is deemed to continue in full force and effect until the Extension Application is determined.

Papua LNG Project

During the first quarter of 2016, the PRL 15 Joint Venture continued work on the compilation of the basis of design, supported by the results of numerous site surveys which have been completed to date. These surveys include metocean, geophysical, geotechnical, topographical and environmental surveys. The PRL 15 Joint Venture also continued discussions on LNG marketing and project financing for development of the Papua LNG Project.

$400 million ANZ led senior secured capital expenditure facility

Subsequent to quarter end, on April 21, 2016, we entered into a $400 million senior secured capital expenditure facility on a syndicated basis arranged by Australia and New Zealand Banking Group Limited (“ANZ”) as sole mandated lead arranger and book runner. The conditions precedent were satisfied on May 6, 2016 with the drawings from the facility being used to, among other things, refinance the $300 million Credit Suisse led syndicated secured loan facility. The ANZ led senior secured capital expenditure facility has an annual interest rate of LIBOR plus 6% and terminates on December 31, 2017, subject to certain interim milestones being achieved. Other lenders in the syndicate include Westpac PNG Limited, Bank of South Pacific Limited, Intesa Sanpaolo SPA, Credit Suisse, SocGen, Morgan Stanley and UBS. Security for the ANZ led senior secured capital expenditure facility includes certain of the Company’s subsidiaries’ assets.

Other matters

During April 2016, we received notice from Puma Energy Pacific Holdings Pte Ltd (Puma) of a claim in relation to sludge which Puma assert was found in the tanks of the refinery at the time the refinery was sold to Puma in June 2014. We have not determined the validity of the claim and accordingly no provision has been made in accounts in relation to the possible outcome of the claim. Should a valid claim be found to exist, our current assessment is that the amount payable will not be material.

Management Discussion and Analysis INTEROIL CORPORATION 8

SELECTED FINANCIAL INFORMATION AND HIGHLIGHTS

Consolidated Results for the Quarters Ended March 31, 2016 and 2015

Consolidated – Operating results	Quarter ended March 31,
($ thousands, except per share data)	2016			2015
Interest revenue		588			11,412
Other		333			1,803
Total revenue		921			13,215
Administrative and general expenses		(10,266	)		(6,354	)
Legal and professional fees		(1,131	)		(1,937	)
Exploration costs, excluding exploration impairment		(3,279	)		(19,261	)
Finance costs, excluding interest expense		(930	)		(6,671	)
Foreign exchange gains		110			691
EBITDA ⁽¹⁾		(14,575	)		(20,317	)
Depreciation and amortization		(196	)		(5	)
Interest expense		(2,132	)		(1,477	)
Loss for the period from continuing operations before income taxes		(16,903	)		(21,799	)
Income tax expense		(75	)		(70	)
Loss for the period		(16,978	)		(21,869	)
Basic loss per share		(0.34	)		(0.44	)
Diluted loss per share		(0.34	)		(0.44	)
Total assets		1,174,800			1,318,120
Total liabilities		389,463			307,685
Total long-term liabilities		88,608			96,000

Notes:

(1)

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

Analysis Comparing Financial Condition as at March 31, 2016 and 2015

As at March 31, 2016, our debt-to-capital ratio (being debt divided by [shareholders’ equity plus debt]) was 19%, compared to 14% as at December 31, 2015, well below our targeted maximum gearing level of 50%. Gearing targets are based on factors that include operating cash flows, cash needs for development, capital market and economic conditions, and are assessed regularly. Our current ratio (being current assets divided by current liabilities), which measures our ability to meet short-term obligations, was 2.0 times as at March 31, 2016, compared to 2.2 times as at December 31, 2015. The current ratio satisfied our internal target of above 1.5 times as at March 31, 2016.

Variance in Total Assets:

As at March 31, 2016, our total assets amounted to $1,174.8 million, compared with $1,191.4 million as at December 31, 2015. The decrease of $16.6 million, or 1%, from December 31, 2015, was primarily due to:

$44.3 million decrease in trade and other receivables, mainly due to receipt of funds from Total in relation to a transition services agreement and an adjustment to the discounted value of sale proceeds receivable from Total as a result of the change to the expected cash flow timing of the interim resource payment under the Total SSA from June 2016 to September 2016.

These decreases have been partially offset by:

$25.9 million increase in exploration and evaluation assets costs capitalized during the period, primarily associated with drilling and testing costs for Antelope-6 in PRL 15.

Management Discussion and Analysis INTEROIL CORPORATION 9

Variance in Total Liabilities:

As at March 31, 2016, our total liabilities amounted to $389.5 million, compared with $391.7 million at December 31, 2015. The decrease of $2.2 million, or 1%, from December 31, 2015, was primarily due to:

$63.4 million decrease in trade and other payables resulting mainly due to the restructure of our activities as a result of the transition of operatorship of PRL 15 to Total and also our plan to defer exploration and appraisal work outside of PRL 15 until the Elk Antelope appraisal program is completed.

This decrease has been partially offset by:

$60.0 million increase in secured loans as a result of drawdowns on the Credit Suisse syndicated secured loan.

Analysis of Consolidated Financial Results Comparing Quarters Ended March 31, 2016 and 2015

Our net loss for the quarter ended March 31, 2016 was $17.0 million, compared with a net loss of $21.9 million for the same quarter in 2015, a decrease of $4.9 million. This was primarily due to the $16.0 million decrease in exploration costs as a result of lower exploration seismic activities in the first quarter of 2016, and also a $5.1 million decrease in finance costs mainly resulting from financing fees incurred on the Credit Suisse led syndicated secured loan facility during the prior year quarter associated with the maturity date extension. These decreases have been partly reduced by the $10.8 million decrease in interest revenue due to the adjustment to the discounted value of sale proceeds receivable from Total as a result of the change to the expected cash flow timing of the interim resource payment under the Total SSA from June 2016 to September 2016. In addition, there was an increase in administrative and general expenses of $3.9 million, mainly due to the restructuring of our operations and corporate functions and also our plan to defer further exploration and appraisal work outside of PRL 15 until the Elk Antelope appraisal program is completed, resulting in costs being expensed as incurred, rather than capitalized.

The table below analyzes key movements, the net of which primarily explains the variance in results between the quarters ended March 31, 2016 and 2015:

		Quarterly Variance ($ millions)
		$	4.9		Net loss variance for the comparative periods primarily due to:
Ø	Interest revenue	$	(10.8	)	Decrease in interest income for the current quarter was mainly due to an adjustment to the amount receivable under the Total SSA as a result of a change in the timing of interim certification payments to September 2016.
Ø	Other revenue	$	(1.5	)	Other revenues for the quarter were comprised of support services (post divestment) recharged to Puma. The volume of support services provided has decreased since the quarter ended March 31, 2015.
Ø	Administrative and general expenses	$	(3.9	)	The increase in administrative and general expenses was mainly due to the restructure of our operations and corporate functions and also our plan to defer further exploration and appraisal work outside of PRL 15 until the Elk Antelope appraisal program is completed, resulting in costs being expensed as incurred, rather than capitalized.
Ø	Legal and professional fees	$	0.8		The decrease in legal and professional fees was mainly due to lower consultant fees during the quarter ended March 31, 2016, due to completion of the office transition from Cairns, Australia, and the arbitration on PRL 15 during the prior year.
Ø	Exploration costs	$	16.0		The decrease in exploration costs was primarily as a result of lower exploration seismic activities in the current year quarter. During the prior year quarter, we expensed seismic activities over the Murua lead in PPL 474, exploration seismic over PPL 475, and airborne gravity survey costs incurred for PPL 476, PPL 477 and PRL15.
Ø	Finance costs	$	5.7		The decrease in finance costs was primarily due to lower facility fees for the Credit Suisse led syndicated secured loan facility. During the quarter ended March 31, 2015, finance costs mainly comprised of facility fees for the maturity date extension of the Credit Suisse facility.
Ø	Foreign exchange (losses)/ gains	$	(0.6	)	The decrease in foreign exchange gains was primarily due to lower depreciation of the PGK against USD as compared to the quarter ended March 31, 2015.
Ø	Depreciation and amortization	$	(0.2	)	The increase in depreciation expense was due to a decrease in the depreciation that could be capitalized to projects as a result of the reduction to our activities.
Ø	Interest expense	$	(0.7	)	The increase in interest expense was largely due to use of the Credit Suisse led syndicated facility during the quarter ended March 31, 2016.

Management Discussion and Analysis INTEROIL CORPORATION 10

Analysis of Consolidated Cash Flows Comparing Quarters Ended March 31, 2016 and 2015

As at March 31, 2016, we had cash, cash equivalents, and restricted cash of $43.6 million (March 31, 2015 - $304.7 million), of which $8.2 million (March 31, 2015 - $8.3 million) was restricted. Of the total restricted cash at March 31, 2016, $8.0 million was restricted as a debt reserve under the Credit Suisse led syndicated secured loan facility and the balance was made up of a cash deposit for lease of office premises and term deposits on our PPLs.

($ thousands)	Quarter ended March 31,
	2016			2015
Net cash (outflows)/inflows from:
Operations		(14,418	)		(33,353	)
Investing		(43,299	)		(63,666	)
Financing		60,000			-
Net cash movement		2,283			(97,019	)
Opening cash		33,069			393,405
Closing cash		35,352			296,386

Cash flows used in operating activities

Cash outflows from operating activities for the quarter ended March 31, 2016 were $14.4 million compared with outflows of $33.4 million for the quarter ended March 31, 2015, a net decrease in cash outflows of $19.0 million.

Management Discussion and Analysis INTEROIL CORPORATION 11

This table outlines key variances in the cash inflows/(outflows) from operating activities between the quarters ended March 31, 2016 and 2015:

		*Quarterly* *variance* *($ millions)*
		$	19.0	Variance for the comparative periods primarily due to:
Ø	Cash used in operations, before changes in operating working capital	$	13.2	The decrease in cash used in operations, before changes in operating working capital for the quarter, was mainly due to the decrease in exploration activities expensed as incurred and financing costs, offset by the increase in administrative expenses.
Ø	Cash generated from operations relating to changes in operating working capital	$	5.8	The decrease in cash used in operations relating to changes in operating working capital was due to decreased trade and other payables due to reduced activities and our plan to defer exploration and appraisal work outside of PRL 15 until the Elk Antelope appraisal program is completed.

Cash flows used in investing activities

Cash outflows from investing activities for the quarter ended March 31, 2016 were $43.3 million compared with an outflow of $63.7 million for the quarter ended March 31, 2015, a net decrease in cash outflows of $20.4 million.

This table outlines key variances in cash (outflows)/inflows from investing activities between the quarters ended March 31, 2016 and 2015:

		Quarterly variance ($ millions)
		$	20.4		Variance for the comparative periods primarily due to:
Ø	Expenditure on exploration and evaluation assets net of JV contributions	$	39.1		The decrease in expenditure on exploration and evaluation assets is due to a reduction in all drilling activities in the quarter ended March 31, 2016.
Ø	Proceeds from sale of drilling consumables, spares and plant and equipment	$	4.3		The increase in the proceeds from sale of drilling consumables, spares and plant and equipment during the quarter ended March 31, 2016 is due to the restructure of our activities and also our plan to defer further exploration and appraisal work outside of PRL 15 until the Elk Antelope appraisal program is completed. As a result, we have disposed of surplus drilling consumables, spares and plant and equipment.
Ø	Cash (used in)/ generated from investing activities relating to change in non-operating working capital	($	23.1	)	The movement in non-operating working capital was primarily related to a reduction in trade payables and accruals in our exploration and development operations, in addition to a decrease in receivables due to receipt of funds from Total related to services provided under the transitional services arrangements for transfer of operatorship to Total.

Cash flows generated from financing activities

Cash inflows from financing activities for the quarter ended March 31, 2016 were $60.0 million compared with nil for the quarter ended March 31, 2015, a net increase in cash inflows of $60.0 million.

Management Discussion and Analysis INTEROIL CORPORATION 12

This table outlines key variances in cash inflows/(outflows) from financing activities between quarters ended March 31, 2016 and 2015:

		*Quarterly* *variance* *($ millions)*
		$	60.0	Variance for the comparative periods primarily due to:
Ø	Proceeds from drawdown of Credit Suisse secured facility	$	60.0	Drawdown of $60.0 million from the Credit Suisse led syndicated secured loan facility during the quarter ended March 31, 2016, compared with no drawdowns during the prior year quarter.

Summary of Consolidated Quarterly Financial Results for Past Eight Quarters

This table contains consolidated results for the eight quarters ended March 31, 2016 on a consolidated basis.

Quarters ended	2016			2015												2014
($ thousands except per share data)	Mar-31			Dec-31			Sep-30			Jun-30			Mar-31			Dec-31			Sep-30			Jun-30
Total revenues		921			11,690			11,822			(13,643	)		13,215			(13,182	)		10,749			13,689
EBITDA ⁽¹⁾		(14,575	)		(81,543	)		(101,838	)		(30,583	)		(20,317	)		(60,443	)		(12,133	)		(10,253	)
Net (loss)/profit		(16,978	)		(83,830	)		(103,725	)		(32,531	)		(21,869	)		(64,205	)		(16,930	)		52,265
From continuing operations		(16,978	)		(83,830	)		(103,725	)		(32,531	)		(21,869	)		(62,474	)		(14,622	)		(15,765	)
From discontinued operations		-			-			-			-			-			(1,731	)		(2,308	)		68,030
Basic (loss)/earnings per share		(0.34	)		(1.69	)		(0.29	)		(0.66	)		(0.44	)		(1.30	)		(0.34	)		1.05
From continuing operations		(0.34	)		(1.69	)		(0.29	)		(0.66	)		(0.44	)		(1.26	)		(0.29	)		(0.31	)
From discontinued operations		-			-			-			-			-			(0.04	)		(0.05	)		1.36
Diluted (loss)/earnings per share		(0.34	)		(1.69	)		(2.09	)		(0.66	)		(0.44	)		(1.30	)		(0.34	)		1.05
From continuing operations		(0.34	)		(1.69	)		(2.09	)		(0.66	)		(0.44	)		(1.26	)		(0.29	)		(0.31	)
From discontinued operations		-			-			-			-			-			(0.04	)		(0.05	)		1.36

(1)

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

LIQUIDITY AND CAPITAL RESOURCES

Summary of Debt Facilities

This table summarizes the debt facilities available to us and the balances outstanding as at March 31, 2016:

Organization		Facility				Balance outstanding March 31, 2016				Weighted average interest rate				Maturity date
Credit Suisse led syndicated secured loan facility		$	300,000,000			$	190,000,000				5.36	%		December 2016

Management Discussion and Analysis INTEROIL CORPORATION 13

Credit Suisse led Syndicated Secured Loan

On June 17, 2014, we entered into a $300.0 million syndicated, senior secured capital expenditure facility through a consortium of banks led by Credit Suisse. The facility was supported by the participating lenders CBA, ANZ, UBS, Macquarie, BSP, Westpac, MUFG and SocGen. The facility has an annual interest rate of LIBOR plus 5% and matures at the end of 2016.

During the quarter ended March 31, 2016, we drew down $60.0 million under this facility. As at March 31, 2016, we were in compliance with the debt covenants.

Other Sources of Capital

Our share of expenditure on exploration wells, appraisal wells and extended well test programs is funded by capital raising activities, debt, cash calls from joint venture partners and asset sales.

Capital Expenditure

Net capital expenditure on exploration and evaluation assets

Net capital expenditures on our exploration and evaluation assets in PNG for the quarter ended March 31, 2016 were $25.9 million, compared with $57.8 million during the same period of 2015.

This analysis outlines key net capital expenditure in the quarter ended March 31, 2016:

	Quarterly movement ($ millions)

	$	501.7		Opening balance of exploration and evaluation assets

	$	25.9		Net capital expenditure consisting of following:

Ø	$	22.6		Costs for drilling and testing of Antelope-6.

Ø	$	4.8		Costs for development survey, environmental and societal studies, preparation works, project finance and operator transition for Papua LNG Project.

Ø	$	(1.5	)	Other expenditures, including indirect project support costs and field care and maintenance for PRL 15, and site preparation costs of the Antelope-7 well, offset by a reduction to inventory due to sales during the quarter.

	$	527.6		Closing balance of exploration and evaluation assets

Gross capital expenditure on exploration and evaluation assets

Gross capital expenditure on our exploration and evaluation assets in PNG for the quarter ended March 31, 2016 was $31.5 million.

Management Discussion and Analysis INTEROIL CORPORATION 14

This analysis outlines key gross capital expenditures in the quarter ended March 31, 2016:

	*Quarterly* *movement* *($ millions)*

	$	31.5	Gross capital expenditure consisting of following:

Ø	$	22.9	Costs for drilling and testing of Antelope-6.

Ø	$	4.9	Costs for development survey, environmental and societal studies, preparation works, project finance and operator transition for Papua LNG Project.

Ø	$	3.7	Other expenditures, including indirect project support costs and field care and maintenance for PRL 15, and site preparation costs of the Antelope-7 well, offset by a reduction to inventory due to sales during the quarter.

Capital Requirements

Our primary use of capital resources has been for exploration and development activities. We have to execute exploration activities within a set timeframe to meet the minimum license commitments in relation to our PPLs and PRLs. Noted below are our contractual obligations and commitments over the next five years which are required at a minimum to maintain our licenses in good standing. Subject to meeting the license commitment requirements, our capital expenditures can be accelerated or decelerated at our discretion.

The PRL 15 Joint Venture is currently considering whether to drill the Antelope-7 appraisal well and a decision is expected to be made before the end of the second quarter of 2016. If the PRL 15 Joint Venture decides not to drill Antelope-7, the certification process would then be implemented with Antelope-6 being the last well in the appraisal program and we would expect the process to be completed by the end of September 2016, at which time we will receive the interim resource certification payment under the Total SSA. In the event the PRL15 Joint Venture decide to drill Antelope-7 the expected timing of the interim resource certification payment will change.

We believe that the revised secured financing facility of $400.0 million led by ANZ will enable us to fund operations until the estimated interim certification payment is received. We can also raise additional funding through asset sales to ensure sufficient cash to be available to further our development plans.

In July 2015, we filed a short form base shelf prospectus with the Alberta Securities Commission and a corresponding registration statement on Form F-10 with the SEC pursuant to the multi-jurisdictional disclosure system. These filings will enable us to add financial flexibility in the future and issue, from time to time, up to an aggregate of $1.0 billion of securities in one or more offerings for a period of 25 months from the effective date of the prospectus. These securities may be debt securities, common shares, preferred shares, warrants or a combination thereof. We expect that we will be able to secure the necessary financing through one, or a combination of, the aforementioned alternatives.

Management Discussion and Analysis INTEROIL CORPORATION 15

Oil and gas exploration and development and liquefaction are capital intensive and our business plans involve raising capital, which depends on market conditions when we raise such capital. Additionally, our PRL 15 Joint Venture share of costs of construction of a liquefaction plant, central processing facility and other infrastructure associated with the proposed Papua LNG Project may amount to billions of dollars and thus exceed our existing cash balances. No assurance can be given that we will obtain new capital or refinance current facilities on terms that are acceptable to us, particularly with market volatility.

Contractual Obligations and Commitments

This table contains information on payments to meet our contracted exploration and debt obligations for each of the next five years and beyond. It should be read in conjunction with our Condensed Consolidated Interim Financial Statements, Consolidated Financial Statements and respective 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
PPLs and PRLs		379,382		7,947		176,135		-		195,300		-		-
Secured loans		192,825		192,825		-		-		-		-		-
Other non-current liabilities		96,000		-		96,000		-		-		-		-
Total		668,207		200,772		272,135		-		195,300		-		-

The PPL and PRL amounts represent our commitments for these licenses as at March 31, 2016. The terms of grant of our PPLs includes commitments for us to spend $351.6 million over the remainder of the six-year terms. The terms of grant of PRL 39 require us to spend $27.8 million on the license area by the end of 2018.

Off Balance Sheet Arrangements

During the quarter and as at March 31, 2016, we had no off balance sheet arrangements or relationships with unconsolidated entities or financial partnerships.

Transactions with Related Parties

Other than remuneration paid to key management personnel, no related party transaction took place during the quarter ended March 31, 2016.

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 March 31, 2016, we had 49,678,460 common shares issued and outstanding (50,397,775 common shares on a fully diluted basis) and no preferred shares issued and outstanding. The potential dilutive instruments outstanding as at March 31, 2016 included employee stock options and restricted stock in respect of 719,315 common shares.

As of May 10, 2016, we had 49,681,960 common shares issued and outstanding (50,434,514 common shares on a fully diluted basis) and no preferred shares issued and outstanding. The potential dilutive instruments outstanding as at May 10, 2016 included employee stock options and restricted stock in respect of 752,554 common shares.

Management Discussion and Analysis INTEROIL CORPORATION 16

RISK FACTORS

Our business operations and financial position are subject to risks. A summary of the key risks that may affect matters addressed in this document have been included under “Forward Looking Statements” above. Detailed risk factors can be found under “Risk Factors” in our 2015 AIF available at www.sedar.com.

CRITICAL ACCOUNTING ESTIMATES

The preparation of financial statements in accordance with IFRS requires our management to make estimates and assumptions that affect the amounts reported in the Condensed Consolidated Interim Financial Statements and accompanying notes. Actual results could differ from those estimates. The effect of changes in estimates on future periods have not been disclosed in the Condensed Consolidated Interim Financial Statements as estimating it is impracticable. During the quarter ended March 31, 2016, there were no changes in the methodology used to make critical accounting estimates to those disclosed in our 2015 MD&A.

For a discussion of those accounting policies, please refer to Note 2 of the notes to our Consolidated Financial Statements for the year ended December 31, 2015, available at www.sedar.com, which summarizes our significant accounting policies.

NEW ACCOUNTING STANDARDS

New accounting standards not yet applicable as at March 31, 2016

These new standards have been issued but are not yet effective for the financial year beginning January 1, 2016 and have not been early adopted:

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

IFRS 15 ‘Revenue from contracts with customers’ (effective from January 1, 2018): The new standard is based on the principle that revenue is recognized when control of a good or service transfers to a customer, so the notion of control replaces the existing notion of risks and rewards. We are currently evaluating the impact of adopting this standard.

IFRS 16 ‘Leases’ (effective from January 1, 2019): The new standard now requires lessees to recognize a lease liability reflecting future lease payments and a ‘right-of-use asset’ for virtually all lease contracts. The standard has an optional exemption for certain short-term leases and leases of low-value assets; however, this exemption can only be applied by lessees. The standard also provides guidance on the definition of a lease (as well as the guidance on the combination and separation of contracts). We are currently evaluating the impact of this standard.

NON-GAAP MEASURES AND RECONCILIATION

Non-GAAP measures, including EBITDA, included in this MD&A are not defined nor have a standardized meaning prescribed by IFRS. Accordingly, they may not be comparable to similar measures provided by other issuers.

Management Discussion and Analysis INTEROIL CORPORATION 17

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

This table reconciles net (loss)/profit from continuing operations, a GAAP measure, to EBITDA from continuing operations, a non-GAAP measure for each of the last eight quarters.

	2016			2015												2014
Quarters ended ($ thousands)	Mar-31			Dec-31			Sep-30			Jun-30			Mar-31			Dec-31			Sep-30			Jun-30
Earnings before interest, taxes, depreciation and amortization		(14,575	)		(81,543	)		(101,838	)		(30,583	)		(20,317	)		(60,443	)		(12,133	)		(10,253	)
Interest expense		(2,132	)		(1,639	)		(1,513	)		(1,492	)		(1,477	)		(1,464	)		(1,367	)		(4,409	)
Income taxes		(75	)		(495	)		(256	)		(207	)		(70	)		(211	)		(199	)		(194	)
Depreciation and amortisation		(196	)		(153	)		(118	)		(249	)		(5	)		(356	)		(923	)		(909	)
From continuing operations		(16,978	)		(83,830	)		(103,725	)		(32,531	)		(21,869	)		(62,474	)		(14,622	)		(15,765	)
From discontinued operations		-			-			-			-			-			(1,731	)		(2,308	)		68,030
Net (loss)/profit		(16,978	)		(83,830	)		(103,725	)		(32,531	)		(21,869	)		(64,205	)		(16,930	)		52,265

PUBLIC SECURITIES FILINGS

You may access additional information about us, including our 2015 AIF, in documents filed with the Canadian Securities Administrators at www.sedar.com, and in documents, including our Form 40-F, filed with the SEC at www.sec.gov. Additional information is also available on our website www.interoil.com.

DISCLOSURE CONTROLS AND PROCEDURES AND INTERNAL CONTROLS OVER FINANCIAL REPORTING

Disclosure Controls and Procedures

Our Chief Executive Officer and Chief Financial Officer have designed, or caused to be designed under their supervision, disclosure controls and procedures to provide reasonable assurance that: (i) material information relating to us is made known to our Chief Executive Officer and Chief Financial Officer by others, particularly during the period in which the annual and interim filings are being prepared; and (ii) information required to be disclosed by us in our annual filings, interim filings or other reports filed or submitted by us under securities legislation is recorded, processed, summarized and reported within the time specified in securities legislation. Such officers have evaluated, or caused to be evaluated under their supervision, the effectiveness of our disclosure controls and procedures at our financial year-end and have concluded that our disclosure controls and procedures are effective at December 31, 2015 for the foregoing purposes.

While our Chief Executive Officer and Chief Financial Officer believe that our disclosure controls and procedures provide reasonable assurance that they are effective, they do not expect that the disclosure controls and procedures will necessarily prevent all errors and fraud. A control system, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met.

Management Discussion and Analysis INTEROIL CORPORATION 18

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, 2015, for the foregoing purpose.

Material Changes in Internal Control over Financial Reporting

No material change in our internal controls over financial reporting were identified during the quarter ended March 31, 2016, that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

A control system, including our disclosure and internal controls and procedures, can provide only reasonable, but not absolute, assurance that the objectives of the control system will be met, no matter how well it is conceived, and it should not be expected that the disclosure and internal controls and procedures will prevent all errors or fraud.

Management Discussion and Analysis INTEROIL CORPORATION 19