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Please refer to the important disclosures and analyst certification on page 2 and the inside back cover of this

document, or on our website www.macquarie.com.au/disclosures.

GLOBAL

IOC US Outperform

Price 2 Feb 11 US$70.78 12-month target US$ 121.00

12-month TSR % +71.0

Valuation US$ 121.00 - DCF (WACC 12.0%) GICS sector Energy

Market cap US$m 3,033

30-day avg turnover US$m 29.5

Number shares on issue m 42.85

Investment fundamentals

Year end 31 Dec 2009A 2010E 2011E 2012E

Revenue m 693.1 1,005.6 2,295.1 2,300.5 EBIT m 31.7 35.2 73.2 76.3

Reported profit m 6.1 -6.8 40.4 40.6 Adjusted profit m 19.9 14.7 40.4 40.6 EPS adj US$ 0.49 0.32 0.81 0.81 EPS adj growth % nmf -34.7 152.5 0.4 PER adj x 144.4 221.0 87.5 87.1

Total DPS US$ 0.00 0.00 0.00 0.00 Total div yield % 0.0 0.0 0.0 0.0 ROA % 5.2 4.4 7.3 6.9 ROE % 6.4 2.7 5.8 5.4 EV/EBITDA x 70.3 64.0 37.1 36.0 Net debt/equity % -3.9 -24.4 -9.9 8.3 P/BV x 7.5 5.1 4.8 4.5

Source: FactSet, Macquarie Research, February 2011

(all figures in USD unless noted)

Macquarie Capital (Europe) Ltd Jason Gammel +44 20 3037 4085 [email protected] Macquarie Capital (USA) Inc John Nelson +1 212 231 2622 [email protected] Matthew Lipton +1 212 231 8036 [email protected]

3 February 2011

InterOil Corp. Papua‟s got a brand new bag Initial stage in development of a prolific resource base

We are initiating coverage of InterOil with an Outperform rating and

US$121 price target. We expect the company and its partners will sanction an

initial 2 mtpa of LNG capacity in Papua New Guinea by mid-2011. We believe

this initial development is the first step in developing InterOil‟s significant

resource base. A pending agreement should allow LNG development to move

forward without a material risk to InterOil‟s balance sheet, and will provide

cashflow to underpin further modular LNG expansions.

Resource development drives stock value

Our price target is based on the risked development potential of the world class

resource base the company has discovered in Papua New Guinea. We believe

the risked value of the Upstream is worth US$103 per share and believe upside

potential could be as high as US$145 per share once greater certainty of

development is gained. It should be noted, no additional resource needs to be

discovered in order for this upside to be reached and that future resource

discoveries from the company‟s exploration portfolio could push our estimate

higher.

LNG development offers outsized IRRs

A prolific resource base, high liquids yield, and low construction costs, in our

opinion, are what make the development of Interoil's resource extremely

attractive. We estimate InterOil’s IRR will be:

~135% on first 2 mtpa investment and related condensate stripping facilities

~1,025% for a 1 mtpa expansion to immediately follow the greenfield

investment

~50% for each internally funded 2 mtpa expansion.

Our development model shows that InterOil would require a natural gas price of

US$(0.84)/mmcf for the initial 2 mtpa project to return a 15% IRR

Upcoming project sanctioning will further boost momentum. We expect sanctioning of the initial LNG/condensate development will occur by mid-2011 and expect further progress to support the stock price thereafter. We view the initial project as an important first step in the development of Interoil‟s resource base.

Macquarie Research InterOil Corp.

3 February 2011 2

Inside

Papua‟s got a brand new bag 3

Investment thesis 4

Resource development agreements and

economic analysis 7

LNG and CSP economic analysis 10

Papua New Guinea‟s emerging resource

opportunity 16

Elk & Antelope Field Overview 18

Elk & Antelope exploration timeline &

details 20

Exploration portfolio 22

Meet the “Mod” Squad 24

Downstream Operations 26

Risks to investment 28

Management Bios 29

Appendices 37

InterOil Corp. Company profile

InterOil Corp. is an integrated energy company with primary operations in Papua

New Guinea. The company is pursuing the development of a condensate

stripping facility and an LNG export facility to monetize their significant natural gas

discoveries in the region. Current operations include a 36k bpd refinery in Port

Moresby and a downstream distribution network. Interoil also holds exploration

licenses on nearly 4m acres in Papua New Guinea.

Fig 1 Major Papua New Guinea license holders

Source: Oil Search Ltd., Macquarie Capital (USA), February 2011

Fig 2 IOC US vs S&P 500

Source: FactSet, Macquarie Capital (USA), February 2011

(all figures in USD unless noted)


3 February 2011 3

Papua‟s got a brand new bag Initial stage in development of a prolific resource base

We are initiating coverage of InterOil with an Outperform rating and US$121 price

target. We expect the company and its partners will sanction an initial 2 mtpa of LNG

capacity in Papua New Guinea by mid-2011. We believe this initial development is the first

step in developing InterOil‟s significant resource base. A pending agreement should allow

LNG development to move forward without a material risk to InterOil‟s balance sheet, and will

provide cashflow to underpin further modular LNG development.

Resource development drives stock value. Our price target is based on the risked

development potential of the world class resource base the company has discovered in

Papua New Guinea. We believe the risked value of the Upstream is worth US$103 per share

and the upside potential could be as high as US$145 per share once greater certainty of

development is gained. It should be noted, no additional resource needs to be discovered in

order for this upside to be reached and that future discoveries from the company‟s exploration

portfolio could push our estimate higher.

LNG development will generate significant FCF. A prolific resource base, high liquids

yield, and low construction costs, in our opinion, are what make the development of Interoil's

resource extremely attractive. We forecast LNG output could expand to 7 mtpa of capacity at

which point gross annual free cashflow would reach about US$2.5b.

Project development offers outsized IRRs. We forecast the complete project IRR is ~50%,

which compares quite favourably to proposed or under-construction Greenfield projects

mostly in the low- to mid-teens. We estimate InterOil’s IRR will be:


~1,025% for a 1 mtpa expansion to immediately follow the greenfield investment



US$(0.84)/mmcf for the initial 2 mtpa project to return a 15% IRR. The negative price is due

to the revenue generated by stripping liquids. Liquid Niugini Gas has estimated that

excluding condensate benefits, the project would still only require a US$0.70/mmcf FOB

natural gas price to generate a 12% IRR.

Upcoming project sanctioning will further boost momentum

We expect sanctioning of the initial LNG/condensate development will occur by mid-2011 and expect further progress to support the stock price thereafter. We view the initial project as an important first step in the development of Interoil‟s resource base.


3 February 2011 4

Investment thesis We are initiating coverage of InterOil with an Outperform rating and a US$121 price

target. Our price target is based on the risked development potential of the world class

resource base the company discovered in Papua New Guinea. We believe the risked value

of the Upstream is worth US$103 per share and place a US$15 per share value on the

Downstream (Refining and Distribution) operations. The current net cash position accounts

for the remaining US$3 in our target.

Development momentum is undervalued. We expect the company and its partners will

sanction an initial 2 mtpa of LNG capacity by mid-2011. We believe this initial development is

the first step in developing InterOil‟s significant resource base. The pending agreement with

Energy World should allow LNG development to move forward without a material risk to

InterOil‟s balance sheet, and will provide cashflow to underpin further modular LNG

development. As such, we do not believe the company requires any long-term purchase

agreements in order to proceed with the project. We expect the project will have 7 mtpa of

capacity in place by year-end 2017.

Fig 3 Initial project sanctioning could pave the way for 7 mtpa by YE2017

Note: represents first year of full operations

Source: Company reports, Macquarie Capital (USA), February 2011

LNG development will generate significant FCF. A prolific resource base, high liquids

yield, and low plant costs, in our opinion, are what would make the development of Interoil‟s

resource extremely attractive. We forecast the project could expand to 7 mtpa of capacity at

which point gross annual free cashflow would reach about US$2.5b. We forecast the first 2

mtpa of capacity alone will generate ~US$9 of our US$11.38 InterOil 2014 CFPS estimate.

Brownfield expansions should further enhance cash generation.

Fig 4 Project profitability & expansion opportunities will generate significant FCF

Source: Company reports, Macquarie Research, February 2011

Greenfield 3 mtpa development worth a risked US$69/sh. We anticipate a FID by mid-

2011 will bring first LNG shipments from the initial 2 mtpa facility in 2H13. Our 25-year DCF

values InterOil‟s net cashflows using a 12% discount rate to arrive at a US$52 per share

value for this initial phase of development. We expect a 1 mtpa brownfield expansion should

come online shortly after the initial phase and that low incremental investment requirements

will generate outstanding returns. We apply a 30% risk factor to this expansion to arrive at a

US$17 per share value. Please see Figure 5 for further details.

Macquarie Forecast Development Schedule*

Train MTPA 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

1 & 2 2.0 - - - 2.0 2.0 2.0 2.0 2.0 2.0 2.0

3 1.0 - - - - 1.0 1.0 1.0 1.0 1.0 1.0

4 2.0 - - - - - - 2.0 2.0 2.0 2.0

5 2.0 - - - - - - - 2.0 2.0 2.0

Total 7.0 - - - 2.0 3.0 3.0 5.0 7.0 7.0 7.0

(1,000)

(500)

-

500

1,000

1,500

2,000

2,500

3,000

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

US$m

(4)

(2)

-

2

4

6

8

10

12

US$b

Cum Project FCF (RHS) Annual Project FCF (LHS)

The pending

agreement with

Energy World

should allow LNG

development to

move forward

without a material

risk to InterOil’s

balance sheet, and

will provide

cashflow to

underpin further

modular LNG

development.


3 February 2011 5

Identified resource will support brownfield expansions worth a risked US$34/sh. The

company has identified approximately 10 tcf of gross resource which we view as sufficient to

support brownfield expansions beyond the initial 3 mtpa development. We assume 2 mtpa

expansion trains will be sanctioned in 2013 and 2014 and will begin operations in late-2016

and 2017, respectively. Our model calculates the gross present value of each 2 mtpa train

expansion is US$3.3b gross if operations were to begin in late-2016. Adjusting for time value

of money on the latter expansion we arrive at an un-risked 4 mtpa expansion value of

US$6.3b gross (US$3.4b net to Interoil). While we view expansions as likely given the scope

of the resource, we apply a 50% risk factor to account for project uncertainty and arrive at a

risked NAV of US$1.7b or US$34 per share. Please see Figure 5 for further details.

Fig 5 We value the upstream at US$103 per share on a risked basis


LNG development offers outsized IRRs. We forecast the complete project IRR is ~50%,

which compares quite favourably to proposed or under-construction Greenfield projects

mostly in the mid-teens. Varying levels of ownership interest in the separate aspects of the

project as well as commercial agreements for initial capital outlays warrant that investors

must take a more granular approach to judge the impact for any single party.

We estimate InterOil’s IRR will be:


~1,025% for a 1 mtpa expansion to immediately follow the greenfield investment


The unusual drop in IRR for the later brownfield expansions is because InterOil has minimal

up-front capital requirements on the first 3 mtpa of capacity. Energy World will pay for plant

construction, and has already purchased long lead-time capital equipment. We provide an

IRR sensitivity analysis for the first 2 mtpa of development in the Appendicies.

Upstream Resource & NPV Summary

Net Risked

Risk Risked Resource NG Condensate

Train NAV Factor NAV bcfe bcf mmbbl

1 & 2 $2,597 0% $2,597 1,632 1,440 32

3 $1,222 30% $855 571 504 11

4 $1,795 50% $898 815 719 16

5 $1,603 50% $802 815 719 16

Total $7,217 $5,151 3,833 3,382 75

/sh $145 $103 77


3 February 2011 6

Downstream business adds US$15 per share to our valuation. InterOil operates a low complexity refinery aimed at producing diesel for the local market in Papua New Guinea. The refinery typically operates below full capacity due to weak local market demand, direct import of products and an inability to make certain export grade quality products. We value the refining business at US$12 per share, or 7x our 2011 EBITDA forecast. The company has also built a dominant network of distribution facilities across Papua New Guinea primarily through acquisition over the past seven years. The majority of petroleum product demand in the country is from the commercial business. As such, demand should continue to be supported over the next few years as construction on LNG facilities moves forward and mining demand stays strong. We value InterOil‟s distribution network at US$3 per share, or 4.5x our 2011 EBITDA forecast.

Fig 6 Downstream valuation


Capital resources and financial needs. In November of 2010 the company completed an

offering of ~2.8m common shares at US$75 per share. The company also placed US$70m of

2.75% convertible notes (including green shoe) due 2015. After deducting underwriting costs

we anticipate the company raised approximately US$265m. Proceeds will be used to repay a

high cost US$25m loan with Clarion Finanz, for capital expenditures on the CSP and LNG

related facilities, and for general corporate purposes.

We believe the recent equity and convertible bond issues should provide considerable

financial flexibility for the company to meet all financial requirements until the LNG project

begins operations in 2013. Once the project is sanctioned we anticipate about US$75m of

funding will be needed for InterOil to provide all necessary capital commitments for both their

and the government‟s carried interest, as well as the continued acquisition of seismic data

and the drilling of two exploration wells. We expect the company will not find any difficulty in

raising this level of capital. Should the company decide to accelerate exploration activities

past our assumed levels additional financing may be required.

Please see our “Risks to investment” section for a further discussion of risks related

to this investment.

Refining EBITDA 84$

Multiple 7.0

Multiple Value ($m) 591$

Distribution EBITDA 32$

Multiple 4.5

Multiple Value ($m) 142$

Downstream Value 733$

/sh $15


3 February 2011 7

Resource development agreements and economic analysis The importance of recent agreements in value creation

Over the last 12 months we believe InterOil and their LNG joint-venture entity, Liquid Niugini

Gas Ltd.1 have made significant strides in securing agreements necessary to sanction their

initial LNG development by mid-2011. Below is a detailed discussion on each of the

agreements the company has secured and our economic analysis and base case

assumptions.

Energy World LNG agreement

In late September InterOil announced that Liquid Niugini Gas Ltd. (joint-venture between

Interoil and Pacific LNG Operations Ltd.) signed a binding Heads of Agreement (HOA) with

Energy World Corporation Ltd. to construct up to 3 mtpa of LNG capacity in Papua New

Guinea. In exchange for their commitment to fully fund plant construction costs, Energy

World will receive a portion of LNG revenues. A definitive agreement is expected by mid-

2011 which should provide greater clarity on terms and conditions, as well as, proposed

financing. Our expectation is that the initial 2 mtpa plant will be operational by late 2013.

Liquid Niugini Gas will also have the right to expand the plant‟s capacity to 3 mtpa.

Energy World fee details. In exchange for their commitment to fully fund the plant, Energy

World will receive 14.5% of LNG revenues for the first 15 years of plant operation and 4.8% of

LNG revenues thereafter. The fee will be subject to agreed deductions, mainly Energy World

paying their proportional share of LNG plant operating costs. The final agreement is

expected to include timing and execution targets that could increase or decrease the fee

percentage Energy World is entitled to by a nominal amount. Energy World placed initial

major component orders for a modular LNG plant in 2007. At the time, the company planned

to use the equipment at their 2 mtpa Sengkang LNG development in Indonesia. While

Energy World still plans to move forward with that project, they have not yet received the

required operating license from the Indonesian Ministry of Energy and Mineral Resources.

Meanwhile, the equipment has now been constructed and is ready for delivery. Thus, the

alliance with Liquids Niugini Gas provides Energy World an outlet to progress their Asian LNG

development strategy and to begin receiving a return on their investments to date.

The Liquid Niugini-Energy World agreement, in our opinion, pulls this project toward the front

of the global LNG development queue, enhances InterOil‟s economics and will allow the

company to accelerate value creation for shareholders.

Moving toward the front of the LNG development queue. The capital costs of Interoil‟s

LNG development rank the lowest of all currently proposed or under-construction projects

on both an absolute and per-unit basis. The lower cost structure makes the project price

competitive and we expect it will allow early market penetration.

Project capital costs are less cumbersome. While LNG development is usually

contingent upon long-term LNG off-take agreements, Energy World has a significant

cost advantage due to their medium-sized modular development strategy. The

company anticipates early stage capital costs will equal US$455/tpa of capacity, or

US$910m. While not insignificant, this initial investment is far below some proposed

mega-projects whose capital costs are expected to exceed US$20bn and

US$1,100/tpa.

1 Liquid Niugini Gas Ltd. is InterOil‟s LNG joint-venture with Pacific LNG Operations Ltd.

For further details about the joint-venture ownership structure please reference the appendices.

Remember to use

side comments in

this section

To insert side

comments

automatically,

highlight text, go to

Templates, and

insert side

comment.

The commercial

agreements InterOil

and their LNG joint-

venture entity have

made over the last

year have

accelerated the

development

timeline and should

set the company on

pace for a mid-2011

FID.


3 February 2011 8

Sanctioning possible without long-term offtake. The project‟s more modest cost

should allow for it to proceed without securing long-term off-take agreements. In

essence, the project can achieve acceptable rates of return under spot market

conditions. While Energy World, will still need to secure construction financing to

move forward with the project, we do not expect off-take agreements will be

necessary to source these funds. As such, we see far fewer impediments to the

progression of this project and believe it is possible for first production by

management’s late-2013 timeline.

Off-take agreements still being pursued. While not necessary, management is

pursuing long-term off-take negotiations with LNG buyers to alleviate some of their

price uncertainty. We believe management is steadfast in their pursuit of a fair price

for their LNG and will not sign an off-take agreement simply to alleviate sales

uncertainty. We are constructive on the medium-term fundamentals of the LNG

market, particularly in the Pacific Rim. A low-cost project that can take advantage of

the spot market is now feasible, which is a significant change in the market from even

just a few years ago

Agreement spurs better project economics for Interoil. Not withstanding the lower

cost-structure which modular development brings, the agreement with Energy World also

significantly improves the expected rates of return for InterOil. Under the preliminary

agreements, Energy World will be responsible for funding the plant‟s construction. By

shrinking InterOil‟s upfront capital commitment, their internal rate of return skyrockets. We

expect InterOil‟s rate of return on the initial 2 mtpa plant will be ~135%.

Project start-up gets the expansion ball rolling. We forecast the initial 2 mtpa plant will

monetize just 1/3 of InterOil‟s discovered resource. The company remains open to

expanding LNG development with Energy World beyond 3 mtpa of capacity, but we note

that cashflows from the initial facility alone should be sufficient to fund further brown-field

expansions. Depending on sanctioning timelines, we believe the unrisked present value of

each additional 2 mtpa train is US$1.6-1.8bn. Our base case assumes the company puts

in place 7 mtpa of capacity by the end of 2017. The company believes it is possible for

them to expand operations to 8 mtpa by 2016, and that further acceleration to 11 mtpa

over the same timeline could be possible with the discovery of additional resource.

While upside ambitions bear monitoring, it should be noted that even our baseline

assumptions have a fair amount of uncertainty in part due to the Energy World agreement.

First and foremost, a definitive deal with Energy World has yet to be signed. Further neither

Energy World nor InterOil have any experience in constructing or operating an LNG facility of

this size. Please see our “Risk to investment” section for a full discussion of all risks related

to the company.

Energy World interests remain only partially aligned. Energy World remains

committed to simultaneously developing a 2 mtpa LNG facility in Indonesia. This facility is

planned to commence first production in 2012. The development timeline has been

extended as the company has been unable to secure operating licenses from the

Indonesian Ministry of Energy and Mineral Resources. While we expect Energy World

should earn a positive rate of return on the agreement with Liquid Niugini Gas in Papua

New Guinea, it is likely to be lower than development of their Indonesian project. Should

the bottleneck in receiving licenses from the Indonesian government resolve itself before a

definitive contract is signed with InterOil, it is likely the company would have a preference

for developing their Indonesian assets over a Papua New Guinea LNG development.

Energy World has expressed interest in developing both projects simultaneously; however,

until we see greater clarity on how this would be financed, we expect it may remain outside

the company‟s current financial constraints. At June 30th, 2010 Energy World had only

US$75m in unrestricted cash and undrawn borrowing capacity. Financing arrangements

for the Papua New Guinea facility have yet to be disclosed.

Energy World has off-take agreements for their Indonesian development. The

company has entered into a memorandum of understanding (MOU) with Indonesia

Power (subsidiary of PLN) for the supply of 1.5 mtpa of LNG over 10 years and

reached a heads of agreement (HOA) with Tokyo Gas for the potential supply of 0.5

mtpa of LNG. We believe both of these contracts will remain tied to the Indonesian

development.

By shrinking

InterOil’s upfront

capital commitment,

their internal rate of

return skyrockets.

We expect InterOil’s

rate of return on the

initial 2 mtpa plant

will be ~135%.


3 February 2011 9

LNG operating expertise remains uncertain. It should be noted Energy World has yet to

install and operate any LNG facility other than their small scale (10k tpa) facility in Northern

Territory, Australia. This facility was closed in 2006. Liquid Niugini Gas has never

operated an LNG facility of any size.

Mitsui condensate stripping plant agreement

In April of 2010 InterOil reached a preliminary agreement2 with Mitsui & Co. Ltd. to jointly

develop a condensate stripping plant (CSP) at InterOil‟s Elk & Antelope field. A definitive

agreement was signed in August of 2010 and plans have further evolved since the Energy

World announcement. The original agreement anticipated the 50/50 joint-venture would

spend US$550m (US$32m of which would be for FEED costs) to build a 400 mmcf/d plant

capable of extracting 9kbd. The original cost estimate also included spending for the drilling

of several gas reinjection wells and related compression equipment. These reinjection wells

are no longer needed as the CSP will be developed in conjunction with the start-up of the first

LNG train. We estimate savings from this will approximate US$150-200m. The company

originally targeted a 1Q11 FID for the project. Now that the CSP will be developed in

conjunction with the first LNG train, however, we anticipate both projects will move to FID

simultaneously by mid-2011.

FID anticipated by mid-2011 and project start-up by late-2013

As noted above, we expect both projects will now essentially move forward on a similar FID

timeline. We anticipate these decisions will be made by mid-2011, however, understand that

all parties are working diligently to accelerate the process. Assuming a positive mid-2011

FID, all parties anticipate that first production will commence by late-2013.

2 Please see the addendix for further details about the joint-venture ownership structure.

Assuming a positive

mid-2011 FID, all

parties anticipate

that first production

will commence by

late-2013.


3 February 2011 10

LNG and CSP economic analysis We forecast the complete project IRR is ~50%, which compares quite favourably to proposed

or under-construction Greenfield projects mostly in the mid-teens. Varying levels of

ownership interest in the separate aspects of the project as well as commercial agreements

for initial capital outlays warrant that investors must take a more granular approach to judge

the impact for any single party. We estimate InterOil’s IRR on the first 2 mtpa investment

and related CSP facilities will be ~135%. Further, the expansion to 3mtpa will generate

~1,025% IRR for the company and each internally funded 2 mtpa plant expansion can

achieve ~50% IRR. The unusual drop in IRR for the later brownfield expansions is because

InterOil has minimal up-front capital requirements on the first 3 mtpa of capacity. Energy

World will pay for plant construction, and has already purchased long lead-time capital

equipment. We provide an IRR sensitivity analysis for the first 2 mtpa of development in the

Appendicies. A prolific resource base, high liquids yield, and low construction costs, in our

opinion, are what make the development of this project extremely attractive.

Low upstream costs. We expect that the initial train will be supported by just 6 wells.

The prolific well deliverability from the Antelope reservoir is what permits this low number

of operating wells. With fewer wells comes less annual operating expenses. We forecast

that annual upstream operating expenses will run approximately US$0.66/mmcfe, or

US$15m for the first 2 mtpa. While high levels of well testing caused the last two Antelope

appraisal wells to cost between an estimated US$60-100m, we expect a development well

at Antelope will cost a more modest US$30-40m. Combined this brings total upstream

DD&A to less than US$0.10/mmcfe.

Liquids revenue enhancement. The proposed condensate stripping facility also allows

for the extraction of high value condensate. We estimate that the stripping of liquids

significantly enhances economics of this project. Given the already low cost structure, the

liquids return actually makes the break-even gas price negative (more detail below).

Low capital investment. LNG development costs for projects that are proposed or under-

construction are more than double the upfront cost expected on this project. The lower

levels of capital investment give the operators a cost advantage over their peers and

should allow for the project to be sanctioned without the signing of long-term off-take

agreements. The return to InterOil is further enhanced by Liquid Niugini‟s agreement with

Energy World which leaves the latter responsible for 2/3 of up-front development costs.

Below we detail the assumptions used in our project development model. Further details can

be found in the appendices.

Upstream assumptions. We assume 10 wells will be necessary over the 25-year plant

life to support 3 mtpa of capacity. All-in, we expect these 10 wells will recover 5.1 tcfe of

resource, or ~500 bcfe each. In our expansion modelling, we assume each 2 mtpa plant

will support ~2.7 tcf of delivered LNG over the facility‟s 25-year life. We assume

condensate yields will average 22.5 bbls/mmcf of natural gas leading to the development

of 60 mmboe of condensate.

Prolific resource base requires low development investment. We assume 6 wells

are used for the initial 3 mtpa development. It should be noted that 4 of these wells

have already been drilled during the exploration and appraisal of the Elk and Antelope

Fields. In addition to the 2 wells required before start-up, we assume 2 additional

wells are drilled at 10 and 15 years of production. We model these wells at a gross

cost of US$35m. All-in, we expect these 10 wells will recover 5.1 tcfe of resource, or

~500 bcfe each.

Recovery rates in excess of 80%. In their Elk and Antelope

resource assessment, GLJ Petroleum Consultants noted that due to

the fields moderate to weak aquifer strength, gas saturation and

anticipated production rates, field recoveries could approximate 83-

87% of OGIP (average 86%). In the report, the Arun gas field in

Indonesia was presented as a potential analog. Ultimate recoveries

for the Arun field are anticipated to reach 94% OGIP.


3 February 2011 11

Plant expansion resource required. Approximately 120 bcf/yr is necessary to feed

each 2 mtpa train the company plans to use for development. To support each train

over its expected 25-year life therefore requires ~3.0 tcf. Due to plant and shipping

losses this figure only equates to ~2.7 tcf of LNG delivered; which is what we base our

resource estimates on.

Condensate yields. We forecast an initial ratio of 22.5 barrels of condensate per

mmcf. As confirmed by Antelope-2, yields are richer at the bottom of the formation

(Antelope-2 stabilized at 24-27 bbls/mmcf), thus our forecasts may prove conservative.

The current assumptions assume recovery of 60 mmbbls of condensate for each 2

mtpa train.

CSP assumptions. We assume CSP expansions will be necessary for the start-up of

trains 4 and 5. The company would ultimately like to see each upstream participant take a

proportionate interest in the CSP; however a final ownership structure has yet to be

determined. We currently assume the CSP will receive a ~US$20/bbl throughput margin

which should yield ~12% IRR, excluding sunk FEED costs.

CSP expansion opportunity. We assume CSP expansions will be necessary when

throughput breaches 400 and 700 mmcf/d, which we currently anticipate will occur at

the start-up of trains 4 and 5, respectively. We expect these expansions will carry a

capital cost of approximately US$230m. The lower cost assumption for the brownfield

expansion is because they benefit from pipelines and site clearing spent in the first

development phase.

CSP ownership structure. The definitive agreement between InterOil and Mitsui

signed in August of 2010 set each partners interest in the project equal at 50%. The

Papua New Guinea government retains the right to farm-in to 22.5% of the CSP

project. The government has yet to express any intention to do so, thus we exclude

their participation in the CSP in our forecasts. Mitsui also retains the right to convert

their 50% investment into a 2.5% interest in the Elk and Antelope fields after

mechanical completion of the plant. We assume Mitsui will exercise this option. As

such, we have modelled CSP economics to reflect a 50/50 ownership structure during

plant construction and for 100% economic benefit accruing to InterOil upon project

start-up. We assume all CSP expansions are proportionately funded by the upstream

contingent.

CSP operating cost. We expect operating costs for the CSP will approximate

US$14/bbl. In order to generate a 12% IRR, we expect the CSP will charge the

upstream operators US$32.50/bbl. Should Mitsui elect not to swap their interest in the

CSP project for a 2.5% interest in the Elk and Antelope Field, we understand that this

charge could rise above US$50/bbl which would meaningfully alter our forecasts.

Liquefaction assumptions. The agreement between Energy World‟s and Liquid Niugini

Gas will see Energy World receive roughly 14.5% of LNG revenues over the initial 15-year

term and 4.8% thereafter. The fee will be subject to agreed deductions and execution

targets could increase or decrease the fee percentage Energy World is entitled to. The

tolling fee to be charged by the liquefaction unit to the upstream operators has yet to be

disclosed. We currently assume the tolling fee matches expected plant operating costs.

Energy World fee. The agreement between Energy World‟s and Liquid Niugini Gas

will see Energy World receive roughly 14.5% of LNG revenues over the initial 15-year

term and 4.8% thereafter. The fee will be subject to agreed deductions, mainly Energy

World paying their proportional share of LNG plant operating costs. The final

agreement is expected to include timing and execution targets that could increase or

decrease the fee percentage Energy World is entitled to.


3 February 2011 12

LNG tolling fee. We expect annual operating costs for the initial plant will equate to

roughly US$35m and that 2 mtpa expansion plants will require roughly US$20m.

These numbers equate to US$0.15-0.30 per mmcf of delivered LNG, indicating

operating costs are in line with the cost structure of larger projects. It has yet to be

determined if this tolling fee will be deemed sufficient by Energy World. Our best

estimates show Energy World could still acquire a low double-digit return at this level,

however we lack critical details and are including sunk costs. While a higher tolling fee

remains a risk to our forecast, we do not anticipate upstream margins will be

meaningfully impacted.

Capital investment and funding considerations. We expect all-in capital costs for the

initial 3 mtpa phase of the project will cost US$1.8bn. A large portion of this will be paid by

Energy World. We have assumed that Mitsui exercises their rights to increase their

interest in the Elk and Antelope fields to 5%. The government is expected to pay their

proportionate share of development costs, however, we expect that InterOil will instead

carry all of the government‟s upfront costs and be provided some accelerated level of cost

recovery upon start-up. Finally, we believe recent equity and convertible bond raises

should provide considerable financial flexibility in order for the company to meet all

financial liabilities until the project begins operations in 2013.

Upstream capital costs. We anticipate total project development costs will

approximate US$1.8bn for the first 3 mtpa of capacity. It should be noted that in our

expansion assumptions this level rises on a per mtpa of capacity as sunk exploration

and appraisal well benefits in the greenfield case are not realized in the expansion case.

These costs more than offset the lower infrastructure spending requirements in the

expansion case. Full detail of our capital cost assumptions can be found in Figure 7.

Fig 7 Capital cost assumptions

* Includes pipelines and field infrastructure

** Includes jetty and breakwater

*** Note: Does not include PNG Government share of capital spending

Source: Company data, Macquarie Capital (USA), February 2011

Mitsui participation. Our model assumes Mitsui exercises their right to convert their

50% CSP ownership interest into a 2.5% interest in the Elk and Antelope fields.

Separately, Mitsui has the option to purchase an additional 2.5% interest in the Elk

and Antelope fields which we assume the company will exercise. The cost for the

additional 2.5% interest has yet to be determined, however, we assume Mitsui will pay

US$275m (10% at FID and 90% at plant start-up) which is equal to the amount they

are required to invest to acquire the initial 2.5% interest. Should another outside party

take an upstream interest for a price other than the valuation implied in the Mitsui

agreement, we believe Mitsui would be required to match this implied valuation.

Initial Expansion

3 mtpa 2 mtpa

of capacity of capacity

Upstream

Wells 70$ 240$

Infrastructure* 30$ 20$

Liquefaction

Plant 1,365$ 900$

Marine Infrastructure** 45$ -$

Other (land clearing, etc.) 10$ 10$

Condensate Stripping

CSP Plant 275$ 230$

Total 1,795$ 1,400$

InterOil's Share of total*** 219$ 729$

We believe recent

equity and

convertible bond

raises should

provide

considerable

financial flexibility in

order for the

company to meet all

financial liabilities

until the project

begins operations in

2013.


3 February 2011 13

Government funding. The government is expected to pay their proportionate share

of development costs from the time a development license is issued and a final

investment decision is achieved. We expect that InterOil will instead carry all of the

government‟s upfront costs and be provided some accelerated level of cost recovery in

addition to their proportionate ownership interest. Given that Energy World is

providing for the majority of upfront capital costs, we do not anticipate this will be

burdensome, however should the government choose to participate in the CSP, we

would not expect the government to pay their proportionate upfront capital cost which

could represent approximately an additional US$60m not currently assumed in our

models. Under this scenario we again would expect for InterOil‟s cost to be recovered

once the plant operations begin.

Financing options. We believe recent equity and convertible bond raises should

provide considerable financial flexibility in order for the Interoil to meet all financial

liabilities until the project begins operations in 2013. Once the project is sanctioned

we anticipate only US$75m of funding will need to be sourced in order for InterOil to

provide all necessary capital commitments for both their and the government‟s carried

interest as well as the continued acquisition of seismic data and the drilling of 2

exploration wells until project start-up. We expect the company will not find any

difficulty in raising this level of capital. Should the company decide to accelerate

exploration activities past our assumed levels additional financing may be required.

Discussion of recent financing. In November of 2010 the company completed an

offering of ~2.8m common shares at US$75 per share. The company also placed

US$70m of 2.75% convertible notes due 2015. After deducting underwriting costs we

anticipate the company raised approximately US$265m. Proceeds are anticipated to

be used to repay a high cost US$25m loan with Clarion Finanz, for CSP and LNG

related facilities capex, and for general corporate purposes.

Fig 8 Recent financing allows considerable flexibility


Break-even gas price


US$(0.84)/mmcf for the initial 2 mtpa project to return a 15% IRR. The negative price is due

to the revenue generated by stripping liquids. Liquid Niugini Gas has estimated that

excluding this subsidy, the project would still only require a US$0.70/mmcf FOB natural gas

price to generate a 12% IRR. As shown in Figure 9, this places the project economics in the

top quartile.

(100)

-

100

200

300

400

500

1Q11 2Q11 3Q11 4Q11 1Q12 2Q12 3Q12 4Q12 1Q13 2Q13 3Q13 4Q13

US$m

Available Cash FCF

Includes anticipated payment

from Mitsui for additional 2.5%

Upstream interest

Assume additional US$75m of

liquidity raised through project

finance

Our development

model shows that

InterOil would

require a natural

gas price of

US$(0.84)/mmcf for

the initial 2 mtpa

project to return a

15% IRR.


3 February 2011 14

Fig 9 Top quartile cost-structure expected

Note: Above figures represent Wood Mackenzie‟s assumptions for the natural gas price necessary to give a 12% IRR over necessary capital and operating expenses. Liquid Niugini Gas Ltd. breakeven prices are based on Pacific LNG estimates using InterOil data. The long-term price noted uses US$90/bbl and a 14.85 slope, while Macquarie estimates use a 14.0 slope.

Source: InterOil Corp., Liquid Niugini Gas Ltd., Wood Mackenzie Ltd., Bloomberg, Macquarie Capital (USA), February 2011

Expansion opportunities

Liquid Niugini Gas and Energy World have reached preliminary agreements on an initial 2

mtpa plant and the option to expand operations to 3 mtpa. We believe the resource InterOil

has already discovered supports expansions beyond this initial agreement. Our models

assume the company sanctions an additional 2 mtpa of capacity by year-end 2013 and 2014

bringing total capacity to 7 mtpa by year-end 2017. It should be noted that recent InterOil

presentations have depicted expansion cases which could see total capacity rise to 8 mtpa or

even a considerable 11 mtpa by 2016. Financing details for this level of expansion have not

yet been secured, thus we view our forecast as a more likely base case.

Fig 10 LNG development timeline

*Macquarie forecast represents first year of full operations while IOC schedule represents on-stream date


Our model assumes that the Upstream partners funds all expansions beyond the initial 3

mtpa of capacity which is defined under the current Energy World agreement. Whether

Energy World chooses to continue participation in the development, we note that the present

value impact of internally funding expansion relative to externally funding (Energy World) is

essentially nil. Energy World‟s continued participation would benefit InterOil by lowering

required capital commitments thus enhancing rates of return. We should note, our decision to

reflect expansion without Energy World‟s participation is not to assume that the partners

relationship is not in good standing, however to reflect that the interests of Energy World and

Liquid Niugini Gas may not be fully aligned. We believe this is due to Energy World‟s

commitment to move forward with their Indonesian LNG project.

Macquarie Forecast Development Schedule*

Train MTPA 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

1 & 2 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0

3 1.0 1.0 1.0 1.0 1.0 1.0 1.0

4 2.0 2.0 2.0 2.0 2.0

5 2.0 2.0 2.0 2.0

Total 7.0 - - - 2.0 3.0 3.0 5.0 7.0 7.0 7.0

InterOil Expansion Case Development Schedule

Train MTPA 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

1 & 2 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0

3 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0

4 2.0 2.0 2.0 2.0 2.0 2.0 2.0

5 2.0 2.0 2.0 2.0 2.0 2.0

Total 8.0 - - 2.0 4.0 6.0 8.0 8.0 8.0 8.0 8.0


3 February 2011 15

Putting a value on the Upstream business – US$103 per share

Tying all of the above together, we place a risk-adjusted value of US$103 per share on the

Upstream business. While our 12% discount rate should already provide a sufficient project

discount given the project specific characteristics (i.e. country risk, operational risk, price risk,

etc.) given timeline uncertainty we also chose to utilize train-by-train risk factors. We view the

initial 3 mtpa of capacity as likely to proceed given the mutual benefits which would accrue to

both Energy World and Liquid Niugini Gas. Funding for expansions beyond this, however

remain, in our opinion, highly dependent on the anticipated cashflows from the initial trains.

As such we have assumed a much higher risk factor on these expansions. Once a positive

investment decision is reached and the consortium begins meeting execution targets we

expect to lower our risk adjustment. Further, the company is still pursuing exploration

activities outside the Elk and Antelope fields which may underpin further expansions. Should

additional discoveries be made we would expect to expand our development schedule.

Fig 11 We value InterOil’s upstream business at US$103



Net Risked

Risk Risked Resource NG Condensate

Train NAV Factor NAV bcfe bcf mmbbl

1 & 2 $2,597 0% $2,597 1,632 1,440 32

3 $1,222 30% $855 571 504 11

4 $1,795 50% $898 815 719 16

5 $1,603 50% $802 815 719 16

Total $7,217 $5,151 3,833 3,382 75

/sh $145 $103 77


3 February 2011 16

Papua New Guinea‟s emerging resource opportunity Proximity to Asia and resource endowment set path for development

Welcome to the Jungle

The Independent State of Papua New Guinea is located in the south-western Pacific Ocean.

It is historically remembered as the site of a World War II major military campaign and often

associated with its past practices of headhunting and cannibalism. The country‟s 7 million

citizens took a step forward when it gained independence from Australia in 1975; however,

civil unrest in the mid-„90s stifled economic development. Prospects have brightened more

recently as foreign investment to exploit natural resource wealth has supported development.

New investments to export LNG from Papua New Guinea should further accelerate economic

activity and are expected to more than double GDP over the next decade. The nation

remains challenged by its lack of transportation infrastructure, poor education systems, and

rugged terrain.

Significant resource discoveries already found in this underexplored basin

Papua New Guinea‟s natural gas resource wealth is gaining attention on the global stage.

Country reserves are listed at roughly 8 tcf, however, the resource potential for this

underexplored basin is many multiples of that. Due to the lack of local demand LNG

development has become the preferred choice to monetize resource discoveries. The PNG

LNG consortium, led by ExxonMobil began construction in 2010 on a two train LNG

development that is expected to start-up in 2014 with a total capacity of 6.6 mtpa. InterOil‟s

development plans anticipate 2 mtpa of capacity to be operational in 2013 with expansion

potential for an additional 6 mtpa by 2016.

Hydrocarbon industry just getting off the ground. Current levels of hydrocarbon

production remain relatively modest. Liquids production is approximately 40k bpd and gas

also contributes ~15 mmcf/d.

Liquids production is fed into a refinery located across the harbor from Port Moresby or

exported.

Current gas production is used to satisfy local demand, however, the PNG LNG

development alone should push the country‟s gas exports to ~1 bcf/d by the middle of

this decade.

Region remains underexplored. Less than 200 wells have been drilled across Papua

New Guinea‟s 215,000 km² of prospective acreage. Additionally, due to the challenging

terrain and immaturity of LNG market a large portion of these wells were only targeting oil.

Early exploration results have garnered global attention. In March of 2009 InterOil

reported that their Antelope-1 well flowed at an adjusted rate of 540 mmcfd. The company

then broke their own record when in December of 2009 announcing the Antelope-2 well

flowed at 775 mmcfd. These world record flow rate underscore how prolific the resource

base in the region can be.

Fiscal regime supports investment

We believe the fiscal terms of investment offered by the government are attractive. Initial

exploration (also referred to in Papua New Guinea as “prospecting”) license terms are for 6

years. These PPLs, as they are referred to, can be extended an additional 5 years on half of

the original area by completing an application and receiving Ministerial approval. Spending

commitments over these periods are negotiable, generally not onerous and provide for exits

provided spending commitments are fulfilled. So long as spending commitments are met, an

operator has a preferential right when re-bidding once both the initial and extension periods

are exhausted.

Spending commitment example. LNG Energy Ltd. was awarded 4 licenses by the PNG

government in 2008. The licenses required an average of US$3m be spent on studies and

indeterminate amounts to 30 km of seismic acquisition over the first two years, required the

drilling of a single exploration well over the next two years periods and a single appraisal

well over the final two years provided a discovery was made.

Less than 200 wells have been drilled

across Papua New Guinea’s 215,000

km² of prospective acreage leaving the

region relatively

underexplored.

Fiscal terms for oil and gas investment

in Papua New Guinea are attractive.


3 February 2011 17

Discoveries must be approved for a retention license (PRL) and development license (PDL)

before operators may begin production. Development licenses are not awarded for entire

blocks; instead a Declaration of Location is made to ring-fence discoveries. For gas

discoveries that are not considered to be commercially viable an operator may apply for a 5

year retention license which may be further extended for two 5 year terms. Marketing and

feasibility studies are typically required for Ministerial approval.

Government royalties are held flat at 2% and State and local land owners have the right to

back into 22.5% of a successful discovery upon proportional payment of sunk costs. Papua

New Guinea has a 30% corporate tax rate for development licenses awarded by year-end

2017 on exploration licenses that were granted 2003-2007.

LNG developments accelerating exploration activity

We expect exploration drilling will accelerate over the next 5 years as operators search for

additional resource to extend facility lives and/or support brownfield LNG expansions. Given

the high impact nature of the resource being discovered in the region we also expect to see

expanded drilling programs from non-LNG affiliated operators, as well as new entrants. If

successful, these parties may proceed with their own LNG development or choose to

participate in or sign a gas supply agreement for future brownfield expansions.

Fly Basin Platform. Exploration activity has picked up on the Fly Basin Platform (also

known as the Forelands or Western Forelands) by operators including Talisman, Sasol, Oil

Search Ltd., Eaglewood Energy Inc., Horizon Oil Ltd. and New Guinea Energy.

Highlands. In the Highlands, ExxonMobil, Oil Search Ltd. and New Guinea Energy have

development and exploration licenses. Santos has a non-operated interest in the Hides

field and SE Gobe.

Gulf of Papua. Talisman and Oil Search Ltd. have operations in the Gulf of Papua.

Central Forelands. InterOil, Oil Search Ltd. and LNG Energy Ltd. operate in the Central

Forelands.

Fig 12 Major Papua New Guinea license holders

Source: Oil Search Ltd., Macquarie Capital (USA), February 2011

Fly Basin Platform

Highlands

Gulf of Papua

Central Forelands

High-impact resource discovery potential is leading

to rising investment in this

underexplored basin from major

international and independent

operators.


3 February 2011 18

Elk & Antelope Field Overview A world class reservoir

InterOil’s entrance into Papua New Guinea exploration

InterOil‟s initial exploration license in Papua New Guinea was awarded in April of 1999. Prior

to InterOil, the last well drilled in the Central Forlands was in 1991 by Petro-Canada. InterOil

originally believed the Eastern Papuan Basin was prospective for oil across Jurassic,

Palaeogene and Cretaceous aged sandstones and limestone. They were successful in

finding hydrocarbon contacts in initial drilling, however, oil shows proved either immature or in

insufficient size to warrant development. Basin characteristics remained encouraging and the

company continued exploration work. Since their entrance InterOil has spent more than

US$400m on exploration and appraisal activity. Management has acquired more than 22k

km of gravity & magnetic surveys, reprocessed over 1,400 km of 2-D seismic and shot an

additional 750 km of 2-D over new areas. The company has drilled 12 wells and experienced

a 1/3 success ratio on wells categorized as exploration (see Figures 31 and 32 in the

Appendices for further detail on individual wells and location). The first significant discoveries

occurred in 2006 and 2008 with positive drilling results at the Elk and Antelope fields,

respectively.

Fig 13 InterOil PPL license map

Source: InterOil Corp., Macquarie Capital (USA), February 2011

Independent resource assessment

InterOil secured GLJ Petroleum Consultants Ltd. (GLJ) to provide an independent resource

assessment of the Elk and Antelope fields. The effective date of the analysis was year-end

2009 and a complete report was returned to the company in February of 2010. GLJ is a well

respected independent evaluation consultant for the oil and gas industry that has been in

operation since 1972. The company has provided expert analysis and critical opinions for a

broad array of client needs, including but not limited to financing, mergers, acquisitions,

divestitures and public reporting. Roger Mahoney, the geophysicist retained by GLJ to

provide the analysis, has over 35 years of experience in seismic acquisition, processing and

interpretation. GLJ‟s conclusion was that the fields hold more than 11 tcf of OGIP and 9 tcf of

recoverable wet gas. Condensate recoveries were estimated at 157 mmboe.

Independent

resource evaluation

consultant GLJ

concluded that the

Elk & Antelope

fields hold more

than 11 tcf of OGIP

and 9 tcf of

recoverable wet

gas. Condensate

recoveries were

estimated at 157

mmboe.


3 February 2011 19

It is our understanding that the analysis performed by GLJ was completed with well data

through drill stem test (DST) #1 at Antelope-2. Since that time InterOil has completed at least

6 more drill stem tests and a completed a 1,700 ft horizontal lateral. Further, these later test

results have been very encouraging. Specifically, in September 2010 InterOil announced that

during the horizontal leg the condensate-to-gas ratio stabilized at 24-27.7 bbls of condensate

per mmcf. This observation is roughly 60% higher than the levels observed in DST #1, and

may support positive revisions to prior estimates.

InterOil has not provided an interim resource assessment update which take into account

these results. Our resource development model estimates a slightly higher level of

recoverable resource as our analysis takes into account more recent drilling results. We

estimate 9.4 tcf of gross gas resource will be developed (+15% versus GLJ estimate) and

expect condensate recoveries may approach 210 mmbbls (+33% versus GLJ estimate).

Fig 14 Elk & Antelope Field geologic model view from east


Elk-Antelope resource sufficient to feed 7 mtpa of LNG capacity

We expect the resource already discovered is sufficient to support 7 mtpa of LNG capacity.

Management has indicated this figure could be as high as 8 or 11 mtpa. Management also

continues to perform exploration activities in the region which could support brownfield

expansion.


3 February 2011 20

Elk & Antelope exploration timeline & details Initial success and the discovery of a world class reservoir

Elk’s objective

The Elk structure was believed to lie on the Puri Anticline east of the Puri-1 well which flowed

at ~1,600 bopd before watering out. The structure was also south-southwest of InterOil‟s

Moose-1 and Moose-2 wells which showed non-commercial levels of oil. Drilling on Elk

began in 2006 and was to test for oil from Puri and Mendi limestone. During Elk pre-drill

seismic analysis and further delineated during the evaluation of Elk, the company also

discovered a large reef structure buried to the south of Elk. Later the company would look to

test this massive structure.

Drilling timeline and detail

Elk-1

Spud: February 2006

Objective: Test for oil across Puri and Mendi limestone

Discussion of results: The well was spud in February of 2006 and was drilled to ~6k

ft encountering the Pendi horizon. The well failed however to make contact with the

Mendi limestone. Oil potential determinations were inconclusive; however drilling

confirmed the discovery of gas and gas liquids. The well reported a 22 mmcf/d flow

rate through a small choke (60/64 in) and the company has disclosed their expectation

that the well can flow at rates up to 102 mmcf/d and 510 bcpd.

Cost estimate: US$35m

Fig 15 Elk Structure seismic view from west


Elk-2

Spud: February 2007

Objective: Move down dip to dill an appraisal well to test reservoir extent, further test

oil potential and try to establish a gas-water contact depth.

Discussion of results: The well was drilled through both Puri and Mendi limestone to

a total depth of ~11k ft. Drilling results showed the formation was thicker than pre-drill

estimates and that flow capacity existed below 8,800 ft. Gas-water contact was

unconfirmed due to a low permeability zone encountered at approximately 7,400 ft.



3 February 2011 21

Elk-4 & 4a

Spud: November 2007

Objective: Moving back up-dip to do further appraisal work on the Elk structure and

to deepen the well below 6,500 ft to test the Antelope structure.

Discussion of results: Elk-4 did not encounter Puri and Mendi limestone formations

during the appraisal portion. The well experienced a gas and gas liquids kick while

penetrating the Antelope structure. After stabilizing the well was drilled deeper and

encountered 166 ft of net reservoir. The well later flowed at 105 mmcf/d and 1.9

kbcpd.


Antelope-1

Spud: October 2008

Objective: Move 1.7 miles south onto Antelope reef structure and confirm gas column

at shallower depths and test structure deliverability.

Discussion of results: The well encountered nearly 2,300 ft of net pay at depths

between 5,500 and 8,500 ft. The well flowed at a rate of 545 mmcf/d of wet gas. The

company estimates a condensate to gas ratio of 13, leaving a dry gas adjusted flow

rate of 382 mmcf/d and 5 kbcpd.

Cost estimate: US$60m (note cost estimate includes extensive well testing)

Antelope-2

Spud: July 2009

Objective: Move to the southern end of the structure to determine the extent of the

field and to evaluate liquids recovery rates at deeper intervals.

Discussion of results: Antelope-2 encountered 1,175 ft of net pay at depths

between depths similar, but slightly deeper than Antelope-1. The well flowed at, a

world record, 705 mmcf/d and 11.2 kbcpd. Given that commercial quantities of gas

were already believed to be discovered, perhaps the most encouraging discovery at

Antelope-2 was a condensate to gas ratio that ranged from 16-28 bbls of condensate

per mmcf. A horizontal extension was also completed on Antelope-2 so that the

company could gain further reservoir understanding.

Cost estimate: US$100 (note cost estimate includes extensive well testing)

Antelope geological evaluation

The Antelope complex is a Late Miocene limestone and carbonate reef structure that has a

dolomite cap. The structure exhibits a number of impressive geological features.

Reservoir Size. The gas column discovered ranges 1,200-2,600 ft with thicker areas

found at the northern tip of the structure. Net pay thickness nearly tops 2,300 ft, rivalling

many large gas finds offshore NW Australia. Even in the southern portion of the structure,

where the reservoir is thinner, a higher pay percentage still leaves the minimum pay

thickness nearly equivalent in height to the Empire State Building. In addition the long

column, the structure stretches more than 2 miles in length and is the width of Manhattan.

Permeability. Antelope‟s natural fracture system is perhaps the most important

contributor to the high conductivity of the reservoir. Clay content is low, leaving passage

ways within the structure unobstructed. Evidence of these high levels of conductivity was

seen during well testing when observed pressure rates continued to outperform model

expectations.

Porosity. Reservoir porosity ranges from 8% to more than 20% across the field. By

comparison, porosity for US plays such as the Eagle Ford ranges 3-15%. Porosity within

the structure is believed to improves at deeper intervals and when moving from north to

south.

Antelope’s natural

fracture system is

perhaps the most

important

contributor to the

high conductivity of

the reservoir. Clay

content is low,

leaving passage

ways within the

structure

unobstructed.


3 February 2011 22

Exploration portfolio Resource potential could rival current discoveries

As we have noted above we believe that Papua New Guinea is underexplored and resource

potential from the region could be sizeable. InterOil has identified 40 leads and prospects

across their 3.9m acres of exploration licenses. We believe 2011 and 2012 will be spent

delineating and high grading their exploration inventory.

Further reef exploration should increase geological knowledge

InterOil‟s success at the Elk and Antelope fields has drawn the attention of many operators

and should accelerate exploration of other dolomitic reef structures by other operators in the

basin. Oil Search, who previously focused their Papua New Guinea operations in the

Highlands area, has recently entered into a farm-in agreement on acreage surrounding

InterOil, perhaps further underscoring the remaining exploration potential.

Exploration inventory highlights

We expect the next targets for exploration drilling will be Bwata West, Wolverine and

Seismosaurus. Management has not provided potential resource sizes for any of these

prospects or timelines for potential drilling.

Bwata West – PPL 237. Bwata West (unsurprisingly) is directly west of the Bwata gas

field discovered in 1960. Bwata is a Miocene aged limestone discovery that flowed at

nearly 30 mmcf/d. Management is excited by the Bwata West structure as they believe is

houses the same petroleum system, however potentially in a larger structure.

Wolverine – PPL 238. Wolverine is another reef structure that is approximately 10-12 km

east of the Antelope field.

Seismosaurus – PPL 237. Seismosaurus is a Miocene aged limestone prospect located

in the southwest corner of PPL 237. We expect additional seismic acquisition and

interpretation will be necessary before the company proceeds with drilling at

Seismosaurus, however note its potential as a possible oil play.

Fig 16 Map of InterOil exploration inventory


Bwata West & Bwata

Elk & Antelope Wolverine

Seismosaurus

We expect the next

targets for

exploration drilling

will be Bwata West,

Wolverine and

Seismosaurus.

Management has

not provided

potential resource

sizes for any of

these prospects or

timelines for

potential drilling.


3 February 2011 23

License commitments and agreements with other parties

We believe that license spending commitments have been met for PPL 237 and 238 due to drilling on Elk and Antelope fields. We understand that PPL 236 does have remaining well commitments.

The company has also entered into several agreements giving purchasers the right to take a

working interest in prior and future drilling opportunities.

IPI agreements. The company originally sold a 25% interest in 8 future wells for

US$125m in 2005. The agreement stipulated that four of the wells would be located in

PPL 238, 1 each in PPL 237 and PL 236 and for the final two to be stipulated by the

owners. Four wells have already drilled (which included the Elk – Antelope discovery). It

should be noted the company has repurchased a portion of these interests. Also, we

highlight that this working interest percentage is quoted prior to the government‟s right to

take up to a 22.5% working interest.

PNG Drilling Ventures Ltd. (PNGDV). InterOil has an agreement with PNGDV in which

InterOil carries PNGDV‟s 6.75% interest in 4 wells. Two of these wells have already been

drilled (Elk-1 and Elk-4a) and two remain. Further, the agreement gives PNGDV the right

to participate in 16 wells after the first four for up to 5.75% at a cost of US$112.5k per 1%

interest, subject to certain adjustments.

PNG Energy Investors (PNGEI). PNGEI has the option to participate in 4.25% of

exploration wells 9-24 on PPL 236, PPL 237 and PPL 238. Only 6 exploration wells have

been drilled to date. PNGEI‟s terms for participation call for the company to pay

US$112.5k per 1% interest, subject to certain adjustments.

New rig will help speed drilling times

The company recently secured a new rig (InterOil rig #3) that is expected to increase the

efficiency of drilling operations and increase capabilities going forward. Unlike InterOil rig #2,

the new rig is not constructed to be easily transportable by helicopter. As such we expect rig

#3 will be deployed to the Elk and Antelope fields for appraisal well drilling while rig #2 will be

used for future exploration activities. Rig #3 underwent modifications in late 2010 and early

2011 and we expect it will be deployed later this year.


3 February 2011 24

Meet the “Mod” Squad Modular LNG development is taking capital costs back in time

We find the modular development of the LNG project further enhances the economics of the

large, low-cost resource base the company has discovered. While EWC will supply the first 2

to 3 mtpa of capacity, we use this section to take a deeper look into the escalating LNG

capital cost and further discuss the potential for expanded use of modular development.

Escalating LNG capital costs

Since the mid-90s LNG plant capital costs averaged ~US$500 per tonne of capacity3.

Interestingly, this figure is forecast to rise over 50% in the next decade. Rising material costs

explain a portion of this rise, as inflation in steel and nickel prices, for example, will no doubt

feed through into higher capital costs. The overwhelming majority of this inflation, however, is

being driven by rising labor costs. A shortage of skilled workers has increased project

competition for labor and driven wages higher. Further exacerbating this competition is the

heavy reliance the world has placed on Australia to meet incremental supply needs over the

next decade. As highlighted by our colleague Adrian Wood last fall, approximately 40% of the

world‟s proposed LNG capacity is in Australia (please see Adrian‟s September 6th note,

Australian LNG outlook: Squeezing through the closing window for further details). With so

many projects competing for a finite set of workers, wage inflation here is likely to outpace

other regions. The shortage is so bad that a report by the Australian National Resource

Sector Taskforce suggested that over the next 5 years the industry will face a shortfall of

36,000 tradespeople and 1,700 engineers. Beyond the overall shortage of skilled

tradespeople, wages for these workers have also risen to compensate for the harsh and/or

remote environments in which the projects often reside. With Australian LNG projects already

sitting on the right-end of the cost-curve due, many have already begun to wonder what the

industry can do to preserve returns.

Canadian Oil Sands example. Wage inflation for craft labor is not a new challenge for

major oil producers. Earlier this decade this same phenomenon played out in the

Canadian Oil Sands industry. Similar to LNG projects, the oil sands are also large capital

intensive investments that require a large number of skilled workers during the initial

construction phase. As crude prices rose over the last decade, sanctioning of new oil

sands projects increased. This put pressure on wages as the number of qualified workers

is relatively inflexible over such a short-time period. Inevitably, project costs inflated and

the break-even price required to base investment advanced ahead of prior industry norms.

The Global Financial Crisis took the wind out of oil prices and caused Canadian operators

to put decelerate investment, however the example serves as a useful reminder of how

labor competition can impact project investment economics.

Can modular LNG development offer a cost advantage?

The basics of trade and technology diffusion seem to be coming together to help the industry

solve this looming problem. Global manufacturers are looking to meet the craft labor

shortages in places like Australia by providing a modular solution that requires fewer skilled

laborers during construction. By moving the construction process back into a manufacturing

facility, providers are able to take advantage of relative labor cost advantages, gain increased

efficiencies from repeated tasks and eliminate any harsh and/or remote climate premium

necessary to attract employees. The price paid for these gains is the loss of custom tailored

facilities. So, is it worth it?

Judging by the trend of escalating costs from non-modular projects and recent modular

project announcements the answer seems to be indicating yes. And by a large margin. To

be sure, project sanctioning is infrequent. Further, even when capital cost estimates are

provided detail around allocation across the upstream, liquefaction and distribution segments

is typically vague. But, the gap seems to be wide enough to give a definitive answer.

3 Source: Wood Mackenzie LNG Tool


3 February 2011 25

During September of last year InterOil and Energy World Corporation announced a HOA to

jointly develop 2 mtpa of LNG capacity in Papua New Guinea with an expected capital cost of

just US$455 per tonne. The key reason for the reversal in cost trends seems to be Energy

World‟s exploitation of scalable modular LNG trains in 0.5 mtpa increments. It is important to

highlight while these costs offer a significant advantage over other investments they are in

line with historical cost trends. In standardizing facility design and reaping efficiencies

through the manufacturing process, modular LNG has taken the labor cost inflation out of

project costs. Please see Figure 17and Table 33 in the Appendices for further detail of

historic and forecast capital cost by project.

Fig 17 LNG plant inflation is forecast to rise >50% in the next decade

Note: bubble size reflects total facility capacity

Please see Table 33 in the appendices for a list of project details.

Source: Wood Mackenzie, Macquarie Capital (USA), February 2011

More details on Energy World’s modular plan

Energy World formed strategic alliances with both Chart Industries and Siemens A.G. in 2007

in order to develop further their mid-scale modular LNG development model.

Chart will be the principal equipment provider for facility cold boxes, liquefaction BOP and

gas treatment equipment.

Siemens will be the principal equipment provider of electrical and rotating equipment and

electrical BOP.

Other Energy World partners include: Gas Technique of France and Arup (Civil

Engineering).

InterOil

(500)

0

500

1,000

1,500

2,000

2,500

3,000

1990 1995 2000 2005 2010 2015 2020

USD/tonne Forecast


3 February 2011 26

Downstream Operations Keeping the focus on returns

We believe management has taken aggressive action to increase the returns from their

Downstream assets. Refining runs have been optimized to maximize the yield of higher value

diesel products. In the predominantly commercial Distribution market management has made

targeted acquisitions to secure a dominant position. Further, the company has worked for

many years with the government to put in place a price setting mechanism that improves the

returns in the Distribution businesses. Unfortunately, a dependency on sweet crudes and

insufficient levels of local market demand has depressed operating leverage.

Simple hydro skimming refinery

InterOil operates the Napa Napa Refinery across the harbor from Port Moresby. The refinery

has a throughput capacity of 36.5 kbpd and the configuration is not equipped to handle high

levels of sour crude. The company primarily aims to maximize diesel output from the facility

in order to meet the needs of the local economy. The refinery typically operates below full

capacity due to weak local market demand, direct import of products and an inability to make

certain export grade quality products. A schematic of the refinery can be found in the

appendices.

Dominant distribution network

The company has built a dominant network of distribution facilities across Papua New Guinea

primarily through acquisition over the past 7 years. The majority of petroleum product

demand in the country is from commercial business. As such, demand should continue to be

supported over the next few years as construction on LNG facilities moves forward and

mining demand stays strong. Further supporting returns, the Independent Consumer and

Competition Commission of Papua New Guinea (ICCC) in November of last year approved

the increase of wholesale margins by 9.7% and retail margins by 6.3%.

Consolidation of local market distribution channels. InterOil began to consolidate the

local market distribution network around the time their refinery became operational in 2004.

The company initially purchased BP‟s PNG distribution assets that year and proceeded to

announce the purchase of a portion of Royal Dutch Shell‟s distribution network the

following year. Management attempted to acquire additional aviation distribution assets

from Shell in 2009, however, was denied the right to due so on the basis that it may

substantially lessen competition.

Commercial customer base. Retail station sales are only expected to contribute ~100 m

of expected ~600 m litres of sales in 2010. Mining and construction demand for diesel fuel

is the largest segment within the commercial business. Aviation demand for jet fuel is also

a major component of this business. Generally speaking, while demand from these buyers

is more stable, the margins are also thinner.

November ICCC report. As noted above, the ICCC, which determines the method for

calculating Distribution margins issued a final report in November 2010. In addition to the

referenced margin revisions, the Commission also determined that going forward

wholesale margins will adjust annually at a rate of CPI + 2.4%.

The company

primarily aims to

maximize diesel

output from their

low complexity

refinery in Papua

New Guinea.


3 February 2011 27

Fig 18 InterOil distribution network

Source: Company presentation, Macquarie Capital (USA), February 2011

Potential Opportunities

We expect management will continue to take a proactive approach in adjusting the margins of

this business to more appropriate levels. Over the coming years there are multiple

opportunities that may support further profitability in the business.

Increased condensate throughput. With the rise in LNG production both in Papua New

Guinea and offshore Australia, condensate production in the region should increase. For

this reason, we expect the company will explore running increased volumes of condensate

in the medium-term. The more condensate the company is able to feed into their refinery,

the greater proportion of lower quality (i.e. discounted) crudes we expect they will be able

to also add in their crude slate.

Becoming a condensate refiner? We view the likelihood of the company shifting to

a condensate only refiner as low given the capital investment requirements necessary

for such a shift in feedstock. A schematic of the investments required to make this

shift necessary can be found in the appendices.

Increased S-T levels of construction and mining activity. Management estimates that

the PNG LNG project alone will soak up an incremental 300m litres of diesel demand over

the next four years. Moreover, the company expects additional tenders of nearly 400m

litres from knock-on or other projects over a similar time period. Higher demand should

remain supportive of Downstream margins in the interim, however it should be noted these

projects will roll-off at some point in time. Also, it has yet to be seen what level of new

demand will be met by direct imports.

Potential Threats

In addition to competition and the impact of operating rates we also note the following

potential threats to the Downstream business.

Refining tax holiday expiration. The company received a six year tax holiday incentive

from the government for opening the first refinery in the country. This holiday, however,

expired at YE10. With nearly US$80 of tax loss carryforwards we do not anticipate the

company will be subject to cash taxes until 2013. Once NOLs are fully depleted, the

company will be subject to a 30% tax rate.

Potential closure of Downstream’s biggest customer. The OK Tedi Mine accounted

for ~20% of 2009 volumes from the Distribution business. The mine is an open-pit mining

operation that produces copper and gold. The mine is anticipated to exhaust its resource

in mid- to late-2013. Mine life extension plans are being evaluated, in which case the mine

could be extended through 2022.


3 February 2011 28

Risks to investment The following risk factors may affect the company’s ability to progress their development program or impact project economics

Geopolitical uncertainty

InterOil‟s operations are focused in the Independent State of Papua New Guinea. The country

is an emerging economy with inadequate transportation infrastructure, poor education systems

and a rugged terrain. Emerging countries may be more susceptible to political instability than

more developed markets. The lack of integrated transportation and infrastructure networks

along with the high level of resource investment in the country could constrain InterOil‟s ability to

advance their LNG export and condensate stripping development project.

Commercial arrangements are key to development timeline

The company and their partners have signed either definitive or preliminary commercial

agreements on which their counterparties may be relied for achieving key milestones or

making important commitments in order for the LNG export and condensate stripping project

to proceed. Until definitive agreements are signed, the company may have limited or no legal

options to enforce these agreements. Further, should these partners fail to meet their

obligations, the company may need to pursue other strategies in order to progress their

project which may include, but is not limited to, raising capital or selling down their ownership

interest in order to fund these development activities.

Also, counterparties may have outside interests that do not align with InterOil or their partners.

Access to capital markets

We currently expect the company has adequate capital resources in which to meet the funding requirements of their development projects. If development costs rise above our expectation, the company chooses an alternate or expanded development strategy and may need to access capital markets. Currently we assume the company will raise US$75m of project finance in order to meet spending commitments before first production.

Foreign currency fluctuations

The company conducts certain business operations in the currency of Papua New Guinea,

the Kina. As such, the company is subject to currency risk from both higher levels of

operating costs as well as their ability to meet debt payments in US Dollars.

Project execution and operational risk

The company and its partners plan to develop and construct an LNG export and condensate

stripping project which will require the coordination of suppliers, contractors and employees

from planning through to first production. Further, high resource development activity in the

region could produce bottlenecks and may force the company or its partners to compete for

services which could delay current projected timelines or cause a rise in projected costs.

Once sanctioned for use, the company will be responsible for running day-to-day operations

of the LNG export and condensate stripping project. InterOil also operates a refinery in

Papua New Guinea which is subject to operational risk.

LNG markets

The company currently has no off-take agreements signed for their LNG export project and

may need to sell future cargoes into a spot pricing environment that is less robust than we

have forecast.


3 February 2011 29

Management Bios InterOil has had operations in Papua New Guinea since the late-90s. We view the

experienced management team as having a thorough understanding of the local market.

They remain focused on the execution of an LNG export strategy and have an ambitious

growth plan for the future.

Phil E. Mulacek – Chairman & Chief Executive Officer

Phil E. Mulacek is the Chairman of the Board of Directors and Chief Executive Officer of

InterOil. He has held these positions since 1997. Mr. Mulacek is the founder and

President of Petroleum Independent Exploration Corporation (PIEC) based in Houston,

Texas. PIEC was established in 1981 for the purposes of oil and gas exploration, drilling

and production, and operated across the southwest portion of the United States. PIEC

led the development of InterOil‟s Napa Napa Refinery and the commercial activities that

were necessary to secure the refinery‟s economic viability. Mr. Mulacek has over 25

years of experience in oil and gas exploration and production and holds a Bachelor of

Science Degree in Petroleum Engineering from Texas Tech University.

Collin Visaggio – Chief Financial Officer

Collin Visaggio is Chief Financial Officer of InterOil. Mr. Visaggio joined the company on July

17, 2006 and was appointed to the position of Chief Financial Officer on October 26, 2006.

Mr. Visaggio is a Certified Practicing Accountant in Australia with a Bachelor and a Masters

Degree in Business. He also attended the Stanford Senior Executive Program in

Management. Mr. Visaggio has 24 years of experience in senior financial and business

positions within Woodside Petroleum and BP Australia. His career has given him financial

and business experience in Exploration and Production, Offshore Gas Production, Oil

Refining, LNG, and Domestic Gas. Mr. Visaggio spent most of his career at Woodside

Petroleum from March 1988 to July 2005, with his most recent positions being Manager,

Compliance and Business for the Africa Business Unit, and Manager, Commercial and

Planning for the Gas Business Unit. His responsibilities included the management of the

business unit financial and business processes and implementing governance. Prior to this

and during his 17 years with Woodside he was Deputy Chief Financial Officer and Financial

Analysis and Planning Manager within Corporate Finance. Prior to joining InterOil, Mr

Visaggio was Chief Financial Officer for Alocit Group Ltd from May 2005 until March 2006.

William J. Jasper III – President & Chief Operating Officer

William J Jasper III is President and Chief Operating Officer of the company. Mr. Jasper

joined on August 30, 2006, and, as President, leads the refining and downstream

business. Prior to joining InterOil, Mr. Jasper had worked for Chevron Pipe Line Company

since 1974, serving in leadership and management capacities over facilities, pipelines and

terminals. Prior to this role, Mr. Jasper served 4 years as Chairman of the West Texas

LPG Partnership Board of Directors and was President and General Manager of Kenai

Pipe Line Company in Alaska and the West Texas Gulf Pipeline in Texas.

Christian M. Vinson – Executive Vice President of Corporate Development and Government Affairs

Christian M. Vinson is Executive Vice President of InterOil and head of Corporate

Development. From 1995 to August 2006 he was Chief Operating Officer. Mr. Vinson

joined the company from Petroleum Independent Exploration Corporation, a Houston,

Texas based oil and gas exploration and production company. Before joining Petroleum

Independent Exploration Corporation, Mr. Vinson was a manager with NUM Corporation, a

Schneider company involved in mechanical and electrical engineering automation, in

Naperville, Illinois where his responsibilities included the establishment of the company‟s

first office in the United States. As InterOil‟s Chief Operating Officer, Mr. Vinson has

responsibility for government and community relations and corporate development in

Papua New Guinea. Mr. Vinson has worked with government and industry leaders in

Papua New Guinea over the last ten years. Mr Vinson earned an Electrical and Mechanical

Engineering degree from Ecole d‟Electricité et Mécanique Industrielles, Paris, France.


3 February 2011 30

Peter Diezmann – General Manager Downstream

Peter Diezmann is General Manager of the company‟s Wholesale and Retail Distribution

business segment and joined in March 2005. Prior to joining, Mr. Diezmann had worked for

BP Australia since 1981, serving in various capacities, including retail, wholesale,

distributor, and terminals & logistics management positions, and as General Manager of

BP Papua New Guinea for four years prior to InterOil‟s acquisition of that business. Mr.

Diezmann holds a Masters of Business Administration (MBA) Degree from James Cook

University in Queensland, Australia.

H. Wayne Hamal – General Manager Exploration & Production

H. Wayne Hamal is General Manager of the Exploration and Production business

segment. Wayne joined the company in 2005 as Senior Drilling and Engineering Manager

prior to taking on the role of GM E&P in 2008. Prior to joining InterOil, since 2002, Wayne

was employed by Marathon Oil Company as Joint Venture Manager, Equatorial Guinea,

where he worked directly with production operations and major projects and on all

communication with the State government and joint interest partners. From 1987 to 2002

Wayne was employed by CMS Oil & Gas Company where from 1999 to 2002 he held the

position, Production Manager, Equatorial Guinea. Mr. Hamal holds a Bachelor of Science

degree in Petroleum Engineering from the Colorado School of Mines.


3 February 2011 31

Fig 19 InterOil Corp. financial summary


Outperform TP =

Income statement - US$m 2009 2010E 2011E 2012E 2013E Macro assumptions 2009 2010E 2011E 2012E 2013E

Upstream core earnings (14) (26) (21) (44) 103 WTI Oil (US$/bbl) 100.03 61.97 79.54 95.13 113.54

Refining core earnings (4) (18) (20) (20) 65 US Natural Gas (US$/mcf) 4.03 4.42 4.40 5.25 5.50

Liquefaction core earnings (1) (1) 0 0 1 LNG Spot (US$/mcf) 8.50 11.19 11.95 13.82 14.29

Downstream core earnings (10) (10) (5) (5) 27 Production assumptions 2009 2010E 2011E 2012E 2013E

Total Corporate charges (12) (2) 0 (17) (12) Oil/liquids (k bbl/d) 0 0 0 0 1

Operational earnings 20 15 40 41 139 Natural Gas (mmcf/d) 0 0 0 0 39

Special items (A/T) 41 58 46 85 (183) Total Production (boe) 0 0 0 0 8

Reported earnings 20 15 40 41 139


Per share 2009 2010E 2011E 2012E 2013E Risk Risked Net Risked Resource

Basic EPS 0.15$ (0.15)$ 0.85$ 0.85$ 2.92$ Train NAV Factor NAV bcfe NG - bcf Cond. - mmbbl

Diluted EPS 0.15$ (0.15)$ 0.81$ 0.81$ 2.77$ 1 & 2 $2,597 0% $2,597 1,632 1,440 32

Adjusted Earnings 0.49$ 0.32$ 0.81$ 0.81$ 2.77$ 3 $1,222 30% $855 571 504 11

Cash Flow from Operations 1.09$ (0.12)$ 1.26$ 1.26$ 3.68$ 4 $1,795 50% $898 815 719 16

Dividend -$ -$ -$ -$ -$ 5 $1,603 50% $802 815 719 16

Total $7,217 $5,151 3,833 3,382 75

Cash flow US$m 2009 2010E 2011E 2012E 2013E /sh $145 $103 77

Net income 6 (7) 40 41 139

DD&A 14 14 16 16 39 Downstream Valuation

Changes in working capital (13) (47) 0 0 0 Refining EBITDA 84$

Operating cash flow 44 (5) 63 63 184 Multiple 7.0

Capital Expenditures (104) (130) (167) (182) (133) Multiple Value ($m) 591$

Major Acquisitions 0 0 0 0 0

Proceeds from Asset Sales 0 14 28 0 248 Distribution EBITDA 32$

Cash from investing (86) (91) (139) (182) 114 Multiple 4.5

Cash Dividends Paid 0 0 0 0 0 Multiple Value ($m) 142$

Issuance/Reduction of Debt, Net (53) 87 0 75 0

Sale/Repurchase of Stock, Net 82 208 0 0 0 Downstream Value 733$

Cash from financing 39 307 (14) 56 4 /sh $15

Balance Sheet US$m 2009 2010E 2011E 2012E 2013E Base Case Assumptions

Cash and Cash Equivalents 46 257 166 104 406 Dil Shs Outstanding (m) 50

Total Debt 53 118 118 193 193 Discount Rate 12%

Shareholders' Equity 429 669 736 777 1,163 Long-term Oil price ($/bbl) 90$

Total Capitalization 481 786 854 970 1,356 LNG slope 0.14

Financial Ratios 2009 2010E 2011E 2012E 2013E Price Target

Debt/Capitalization 11% 15% 14% 20% 14% Scenario $/sh Notes

Net Debt/Capitalization 1% -18% -6% 9% -16% Base Case $121 See box above

Return on Average Equity 6% 3% 6% 5% 14% Downside $54 Assumes 14% discount rate & 30% discount to risked NAV

Return on Average Capital Employed 7% 4% 8% 7% 17% Upside $159 Unrisked NAV at 12% discount rate

InterOil Corp. $121

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Fig 20 Macquarie forecast Liquid Niugini Gas Ltd. LNG Development schedule


Fig 21 Liquid Niugini Gas Ltd. All-Party LNG Development & CSP economic analysis


Train MTPA 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

1 & 2 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0

3 1.0 1.0 1.0 1.0 1.0 1.0 1.0

4 2.0 2.0 2.0 2.0 2.0

5 2.0 2.0 2.0 2.0

Total 7.0 - - - 2.0 3.0 3.0 5.0 7.0 7.0 7.0

*First year each train will run at full capacity

FCF (US$m) 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025

Train 1 & 2 - MTPA 1 & 2

Upstream - (61) (86) 186 747 745 745 745 748 746 746 746 748 675 740 737

CSP - (55) (138) (68) 52 52 52 52 52 52 52 52 52 50 - -

Liquefaction - (303) (303) (270) 135 135 135 135 135 135 135 135 135 135 135 135

Total - (419) (526) (152) 934 931 931 931 935 932 932 932 935 859 875 872

NPV $4,151

IRR 50%

Train 3 - MTPA 3 - (153) (154) (23) 518 518 518 518 518 518 518 518 518 426 513

NPV $2,284

IRR 71%

Train 4 - MTPA 4 & 5 - (213) (298) (56) 516 516 516 516 516 516 516 516 516

NPV $2,083

IRR 52%

Train 5 - MTPA 6 & 7 - (213) (298) (56) 516 516 516 516 516 516 516 516

NPV $2,083

IRR 52%

Total FCF - (419) (679) (306) 698 938 1,095 1,909 2,484 2,482 2,482 2,482 2,486 2,410 2,334 2,418

NPV $9,578

IRR 53%

Cumulative FCF - (419) (1,098) (1,405) (707) 231 1,326 3,235 5,718 8,200 10,681 13,164 15,649 18,059 20,393 22,811

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Fig 22 Liquid Niugini Gas Ltd. LNG Development - All-Party Upstream economic analysis (first 2 mtpa of capacity only)


2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025

Natural gas production (mmcfd) - LNG 3,077 - - - 83 334 334 334 334 334 334 334 334 334 334 334 334

Condensate production (mbd) 60 - - - 1.9 7.5 7.5 7.5 7.5 7.5 7.5 7.5 7.5 7.5 7.3 7.1 6.9

Total production (kbpd) 573 - - - 16 63 63 63 63 63 63 63 63 63 63 63 62

Total Contracted volumes - - - - - - - - - - - - -

% of volumes contracted 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

Uncontracted volumes - - - 73 291 291 291 291 291 291 291 291 291 291 291 291

LNG deliveries (mmtpa) 51 - - - 1 2 2 2 2 2 2 2 2 2 2 2 2

LNG deliveries (mmcfd) 2,687 - - - 73 291 291 291 291 291 291 291 291 291 291 291 291

LNG pricing formula (contract) 10.03 11.99 13.82 11.34 11.34 11.34 11.34 11.34 11.34 11.34 11.34 11.34 11.34 11.34 11.34 11.34

LNG price (uncontracted) 11.34 11.34 11.34 11.34 11.34 11.34 11.34 11.34 11.34 11.34 11.34 11.34 11.34 11.34 11.34 11.34

Wellhead condensate price 84.00 100.41 119.81 95.00 95.00 95.00 95.00 95.00 95.00 95.00 95.00 95.00 95.00 95.00 95.00 95.00

LNG Revenues 30,465 - - - 301 1,209 1,206 1,206 1,206 1,209 1,206 1,206 1,206 1,209 1,206 1,206 1,206

EWC Payment - - - (44) (175) (175) (175) (175) (175) (175) (175) (175) (175) (175) (175) (175)

Net LNG Revenues - - - 258 1,034 1,031 1,031 1,031 1,034 1,031 1,031 1,031 1,034 1,031 1,031 1,031

Condensate Revenues 5,671 - - - 65 261 260 260 260 261 260 260 260 261 253 245 238

Other Revenues

Total Revenue - - - 323 1,295 1,291 1,291 1,291 1,295 1,291 1,291 1,291 1,295 1,283 1,276 1,269

Gas Purchases - Internal - - - - - - - - - - - - - - - - -

3rd Party Gas Purchases - - - - - - - - - - - - - - - - -

LOE 378 - - - 4 15 15 15 15 15 15 15 15 15 15 15 15

Condensate Plant Operating Expenses - - - 22 89 89 89 89 89 89 89 89 89 86 84 81

Royalty - - - 7 29 29 29 29 29 29 29 29 29 29 29 29

LNG Plant operating expenses 884 - - - 9 35 35 35 35 35 35 35 35 35 35 35 35

Shipping fees 1,713 - - - 17 68 68 68 68 68 68 68 68 68 68 68 68

Other -

Total Cash Expenses 5,637 - - - 59 237 236 236 236 237 236 236 236 237 234 231 228

Depreciation (for tax calc) 613 - - - 30 31 31 31 31 31 31 31 32 32 37 37 37

Cash flow before taxes & C&E 27,251 - - - 264 1,058 1,055 1,055 1,055 1,058 1,055 1,055 1,055 1,058 1,050 1,045 1,041

Income taxes 7,992 - - - 70 308 307 307 307 308 307 307 307 308 304 303 301

Operational cash flow 19,260 - - - 194 750 748 748 748 750 748 748 748 750 746 743 739

Capital expenditures 340 - 61 86 8 3 3 3 3 2 2 2 2 2 71 2 2

Free cash flow 18,920 - (61) (86) 186 747 745 745 745 748 746 746 746 748 675 740 737

NPV $4,173

IRR 163%

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Fig 23 Liquid Niugini Gas Ltd. LNG Development - Energy World economic analysis (first 2 mtpa of capacity only)


Fig 24 Liquid Niugini Gas Ltd. LNG Development – condensate stripping plant (CSP) economic analysis (first 2 mtpa of capacity only)


2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025

Total delivered LNG (mmcfd) - - - 73 291 291 291 291 291 291 291 291 291 291 291 291

Initial Contract Period (yrs) 15 - - - 1 2 3 4 5 6 7 8 9 10 11 12 13

% of LNG throughput for EWC <15 yr 14.5% 14.5% 14.5% 14.5% 14.5% 14.5% 14.5% 14.5% 14.5% 14.5% 14.5% 14.5% 14.5% 14.5% 14.5% 14.5% 14.5%

EWC Payment >15 yr 4.8% - - - 44 175 175 175 175 175 175 175 175 175 175 175 175

Less related costs - - - 1 5 5 5 5 5 5 5 5 5 5 5 5

Total Net EWC payment - - - 42 170 170 170 170 170 170 170 170 170 170 170 170

Liquefaction Opex 0.33$ - - - 9 35 35 35 35 35 35 35 35 35 35 35 35

DD&A 10 40 40 40 40 40 40 40 40 40 40 40 40

Taxes - - - 10 39 39 39 39 39 39 39 39 39 39 39 39

Forecast EWC CFO - - - 33 131 131 131 131 131 131 131 131 131 131 131 131

Forecast EWC Capex (303) (303) (303)

Net EWC Cashflow - (303) (303) (271) 131 131 131 131 131 131 131 131 131 131 131 131

IRR 11.1%

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025

NG Production - - - 83 334 334 334 334 334 334 334 334 334 334 334 334

Condensate production (mbd) - - - 2 8 8 8 8 8 8 8 8 8 7 7 7

Revenue 32.50$ - - - 22 89 89 89 89 89 89 89 89 89 86

CSP Opex 0.15$ - - - 4 18 18 18 18 18 18 18 18 18 18

DD&A 7 7 7 7 7 7 7 7 7 7 7

Taxes - - - 3 19 19 19 19 19 19 19 19 19 18

Forecast CSP CFO - - - 14 52 52 52 52 52 52 52 52 52 50

Forecast CSP Capex (55) (138) (83)

Net CSP Cashflow - (55) (138) (68) 52 52 52 52 52 52 52 52 52 50 - -

Net Income - - - 8 45 45 45 45 45 45 45 45 45 43 - -

IRR 12.1% 7.6%

Ma

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3 F

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3

5

Fig 25 Liquid Niugini Gas Ltd. LNG Development – 1 mtpa plant capacity expansion economic analysis (assuming Energy World funded)


Year 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15

LNG sales (mmtpa) 25% 0.25 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00

Total delivered LNG (mmcfd) 1,342 - - - 36 146 146 146 146 146 146 146 146 146 146 146

LNG plant input (mmcfd) - - - 42 167 167 167 167 167 167 167 167 167 167 167

Natural gas production (mmcfd) - LNG - - - 42 167 167 167 167 167 167 167 167 167 167 167

Condensate production (mbd) 30 1 4 4 4 4 4 4 4 4 4 4 4

Total production (kbpd) - - - 8 32 32 32 32 32 32 32 32 32 31 31

Contracted volumes (mmtpa) 0% - - - - - - - - - - - - - - -

Uncontracted volumes - - - 42 167 167 167 167 167 167 167 167 167 167 167




LNG Revenues - - - 173 691 691 691 691 691 691 691 691 691 691 691

EWC Payment - - - (25) (100) (100) (100) (100) (100) (100) (100) (100) (100) (100) (100)

Net LNG Revenues - - - 148 590 590 590 590 590 590 590 590 590 590 590

Condensate Revenues - - - 33 130 130 130 130 130 130 130 130 130 126 123

Other Revenues

Total Revenue - - - 180 721 721 721 721 721 721 721 721 721 717 713

LOE 0.66$ - - - 2 8 8 8 8 8 8 8 8 8 8 8

Condensate Plant Operating Expenses 0.15$ - - - 2 9 9 9 9 9 9 9 9 9 9 9

Royalty - - - 4 16 16 16 16 16 16 16 16 16 16 16

LNG Plant operating expenses 10$ - - - 3 10 10 10 10 10 10 10 10 10 10 10

Shipping fees 0.64$ - - - 10 39 39 39 39 39 39 39 39 39 39 39

Other -

Total Cash Expenses 2,058 - - - 21 82 82 82 82 82 82 82 82 82 82 82

Upstream DD&A 0.45$ - - - 1 5 5 5 5 5 5 5 5 5 5 5

CSP DD&A 2 8 8 8 8 8 8 8 8 8 8 8

Liquefaction DD&A 0.25$ - - - 0 0 0 0 0 0 0 0 0 0 0 0

Total DD&A (for tax calc) 253 - - - 3 13 13 13 13 13 13 13 13 13 13 13

Cash flow before taxes & C&E 16,347 - - - 160 639 639 639 639 639 639 639 639 639 635 631

Income taxes 30% - - - 47 188 188 188 188 188 188 188 188 188 186 185

Operational cash flow 11,519 - - - 113 451 451 451 451 451 451 451 451 451 448 446

Upstream Capital expenditures 130$ - 39 88 2 2 2 2 2 1 1 1 1 1 91 1

CSP Capital expendiutres 144$ 23 58 35 1 1 1 1 1 1 1 1 1 1 1

Liquefaction Facility Capital expenditures -$ - - -

Liquefaction Site Capital expenditures 7$ - 1 3 2 0 0 0 0 0 0 0 0 0 0 0

Total Capital expenditures 485$ - 63 148 38 3 3 3 3 3 3 3 3 3 92 3

Free cashflow 11,033 - (63) (148) 75 448 448 448 448 448 448 448 448 448 356 443

NPV $2,103

IRR 97%

Expansion from 2mtpa to 3 mtpa

Free cashflow - (1) (3) 111 448 448 448 448 448 448 448 448 448 356 443

NPV $2,279

IRR 1026%

Ma

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Fig 26 Liquid Niugini Gas Ltd. LNG Development – 1 mtpa plant capacity expansion economic analysis (assuming Upstream partner-funded)


Year 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15

LNG sales (mmtpa) 25% 0.25 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00

Total delivered LNG (mmcfd) 1,342 - - - 36 146 146 146 146 146 146 146 146 146 146 146

LNG plant input (mmcfd) - - - 42 167 167 167 167 167 167 167 167 167 167 167

Natural gas production (mmcfd) - LNG - - - 42 167 167 167 167 167 167 167 167 167 167 167

Condensate production (mbd) 30 1 4 4 4 4 4 4 4 4 4 4 4

Total production (kbpd) - - - 8 32 32 32 32 32 32 32 32 32 31 31

Contracted volumes (mmtpa) 0% - - - - - - - - - - - - - - -

Uncontracted volumes - - - 42 167 167 167 167 167 167 167 167 167 167 167




LNG Revenues - - - 173 691 691 691 691 691 691 691 691 691 691 691

Condensate Revenues - - - 33 130 130 130 130 130 130 130 130 130 126 123

Other Revenues

Total Revenue - - - 205 821 821 821 821 821 821 821 821 821 817 813

LOE 0.66$ - - - 2 8 8 8 8 8 8 8 8 8 8 8

Condensate Plant Operating Expenses 0.15$ - - - 2 9 9 9 9 9 9 9 9 9 9 9

Royalty - - - 4 16 16 16 16 16 16 16 16 16 16 16

LNG Plant operating expenses 10$ - - - 3 10 10 10 10 10 10 10 10 10 10 10

Shipping fees 0.64$ - - - 10 39 39 39 39 39 39 39 39 39 39 39

Other -

Total Cash Expenses 2,058 - - - 21 82 82 82 82 82 82 82 82 82 82 82

Upstream DD&A 0.45$ - - - 1 5 5 5 5 5 5 5 5 5 5 5

CSP DD&A 2 8 8 8 8 8 8 8 8 8 8 8

Liquefaction DD&A 22.75$ - - - 6 23 23 23 23 23 23 23 23 23 23 23

Total DD&A (for tax calc) 821 - - - 9 36 36 36 36 36 36 36 36 36 36 36

Cash flow before taxes & C&E 18,205 - - - 185 739 739 739 739 739 739 739 739 739 735 731

Income taxes 30% - - - 53 211 211 211 211 211 211 211 211 211 210 209

Operational cash flow 12,990 - - - 132 528 528 528 528 528 528 528 528 528 525 523

Upstream Capital expenditures 130$ - 39 88 2 2 2 2 2 1 1 1 1 1 91 1

CSP Capital expendiutres 144$ 23 58 35 1 1 1 1 1 1 1 1 1 1 1

Liquefaction Facility Capital expenditures 450$ 150 150 150

Liquefaction Site Capital expenditures 233$ - 1 3 2 9 9 9 9 9 9 9 9 9 9 9

Total Capital expenditures 1,160$ - 213 298 188 12 12 12 12 12 12 12 12 12 101 12

Free cashflow 11,830 - (213) (298) (56) 516 516 516 516 516 516 516 516 516 424 511

NPV $2,101

IRR 52%


3 February 2011 37

Appendices

Fig 27 InterOil IRR sensitivity to the first 2 mtpa LNG facility & CSP development


Fig 28 Liquid Niugini Gas Ltd. (LNG joint-venture) ownership structure


Change in crude px

70$ 80$ 90$ 100$ 110$

136.9% (20)$ (10)$ -$ 10$ 20$

Crude 0.12 (0.02) 102.8% 114.4% 125.2% 135.4% 143.8%

Relationship 0.13 (0.01) 108.2% 120.1% 131.2% 141.6% 149.8%

to LNG 0.14 - 113.3% 125.5% 136.9% 147.7% 155.6%

Price 0.15 0.01 118.3% 130.8% 142.5% 153.6% 161.2%

0.16 0.02 123.1% 136.0% 148.0% 159.3% 166.7%

Change in crude px

70$ 80$ 90$ 100$ 110$

136.9% (20)$ (10)$ -$ 10$ 20$

-10% 120.1% 133.0% 145.0% 156.4% 164.7%

Cap Ex -5% 116.6% 129.1% 140.8% 151.9% 160.0%

Inflation 0% 113.3% 125.5% 136.9% 147.7% 155.6%

5% 110.3% 122.2% 133.3% 143.8% 151.5%

10% 107.4% 119.1% 129.9% 140.2% 147.7%

Uncontracted LNG Px (flat)

136.9% 8.00$ 10.00$ 11.35$ 13.00$ 15.00$

-10% 118.5% 134.9% 145.1% 156.9% 170.4%

Cap Ex -5% 115.1% 130.9% 140.9% 152.4% 165.5%

Inflation 0% 111.8% 127.3% 137.0% 148.2% 161.0%

5% 108.8% 123.9% 133.4% 144.3% 156.8%

10% 106.0% 120.7% 130.0% 140.7% 152.8%

*InterOil LNG Holdings Inc. held a 86.66% economic interest as of 9/30/10, which will be equalized to

52.5% over time as Pacific LNG Operations Ltd. makes cash contributions to the joint-venture

Liquid Niugini Gas Ltd.

PNG LNG Inc.

100%

InterOil LNG Holdings Inc.

50% voting

52.5% economic*

Pacific LNG Operations

Ltd.

50% voting

47.5% economic*

Clarion Finanz AG.

Switzerland


3 February 2011 38

Fig 29 Condensate stripping facility ownership structure


Fig 30 Elk-Antelope field ownership interests


*Note: the Papua New Guinea State Government and Local Land Owners have the right to farm-in to

22.5% of the Condensate Stripping Facility. They have not exercised this right at 9/30/10.

Papua New Guinea State

Government & Local Land

Owners

(22.5%) *

Condensate Stripping

Facility

InterOil Corp.

50%/(38.75%) *

Mitsui & Co., Ltd.

50%/(38.75%) *

w/ State

participation

Working Working

Interest Interest

Assumed YE10

InterOil* 75.6% 58.6%

IPI holders 15.1% 11.7%

PNGDV 6.8% 5.2%

Pacific LNG 2.5% 1.9%

Petromin - PNG State entity 0.0% 20.5%

PNG landowners 0.0% 2.0%

Total 100.0% 100.0%

* Mitsui holds the right to acquire up to 5% of InterOil's interest


3 February 2011 39

Fig 31 InterOil Papua New Guinea exploration summary

Source: InterOil Corp., Macquarie Research, February 2011

Fig 32 InterOil Papua New Guinea exploration well map



3 February 2011 40

Fig 33 LNG facility capital cost

Source: Wood Mackenzie Ltd., Macquarie Research, February 2011

Capex US$

Project $USm mmtpa Capex/Tonne Startup

MLNG Dua 3,505$ 9.0 389$ 1995

Qatargas-1 3,927$ 9.7 405$ 1996

RasGas I 2,680$ 6.6 406$ 1999

Atlantic LNG 1 1,391$ 3.2 435$ 1999

NLNG Base 5,162$ 6.7 773$ 1999

OLNG 2,693$ 7.2 374$ 2000

Atlantic LNG 2&3 1,364$ 6.8 201$ 2002

NLNG Expansion 2,381$ 3.3 713$ 2002

MLNG Tiga 2,385$ 7.4 322$ 2003

RasGas II 2,741$ 14.1 194$ 2004

Qalhat LNG 812$ 3.7 219$ 2005

ELNG 2 1,011$ 3.6 281$ 2005

Damietta 1,530$ 5.0 306$ 2005

ELNG 1 1,907$ 3.6 530$ 2005

Atlantic LNG 4 1,480$ 5.2 285$ 2006

NLNG Plus 2,702$ 8.1 334$ 2006

Darwin 2,014$ 3.6 560$ 2006

EG LNG 1,658$ 3.7 446$ 2007

NLNG 6 2,054$ 4.1 507$ 2007

Snohvit 8,269$ 4.1 2,017$ 2007

RL 3 5,653$ 15.6 362$ 2009

Qatargas-2 6,661$ 15.6 427$ 2009

Sakhalin 2 4,347$ 9.6 453$ 2009

Yemen LNG 4,282$ 6.7 639$ 2009

Qatargas-3 3,459$ 7.8 443$ 2010

Peru LNG 3,999$ 4.5 899$ 2010

Qatargas-4 4,609$ 7.8 591$ 2011

Pluto 7,035$ 4.8 1,466$ 2011

Angola LNG 7,342$ 5.2 1,412$ 2012

IOC PNG 910$ 2.0 455$ 2013

QCLNG 8,368$ 8.5 984$ 2014

PNG LNG 7,933$ 6.6 1,202$ 2014

Gorgon 20,230$ 15.0 1,349$ 2014

GLNG 10,925$ 7.2 1,517$ 2014

Australia Pacific LNG 8,436$ 7.4 1,140$ 2016

Wheatstone LNG 21,466$ 8.6 2,496$ 2016

Ichthys 9,510$ 8.4 1,132$ 2017

Brass LNG 13,073$ 10.0 1,307$ 2017

Prelude FLNG 5,508$ 3.5 1,574$ 2017

NLNG Seven Plus 7,817$ 8.4 931$ 2018

Browse 13,872$ 12.0 1,156$ 2018

Average 771$

Weighted Average 773$


3 February 2011 41

Fig 34 InterOil Napa Napa Refinery schematic


Fig 35 InterOil Napa Napa Refinery schematic with potential expansion



3 February 2011 42

Important disclosures:

Recommendation definitions

Macquarie - Australia/New Zealand Outperform – return >3% in excess of benchmark return Neutral – return within 3% of benchmark return Underperform – return >3% below benchmark return

Benchmark return is determined by long term nominal GDP growth plus 12 month forward market dividend yield

Macquarie – Asia/Europe Outperform – expected return >+10% Neutral – expected return from -10% to +10% Underperform – expected return <-10%

Macquarie First South - South Africa Outperform – expected return >+10% Neutral – expected return from -10% to +10% Underperform – expected return <-10%

Macquarie - Canada

Outperform – return >5% in excess of benchmark return Neutral – return within 5% of benchmark return Underperform – return >5% below benchmark return

Macquarie - USA Outperform (Buy) – return >5% in excess of Russell 3000 index return Neutral (Hold) – return within 5% of Russell 3000 index return Underperform (Sell)– return >5% below Russell 3000 index return

Volatility index definition*

This is calculated from the volatility of historical price movements. Very high–highest risk – Stock should be

expected to move up or down 60–100% in a year – investors should be aware this stock is highly speculative. High – stock should be expected to move up or down at least 40–60% in a year – investors should be aware this stock could be speculative. Medium – stock should be expected to move up or down at least 30–40% in a year. Low–medium – stock should be expected to move up or down at least 25–30% in a year. Low – stock should be expected to move up or down at least 15–25% in a year. * Applicable to Australian/NZ/Canada stocks only

Recommendations – 12 months Note: Quant recommendations may differ from Fundamental Analyst recommendations

Financial definitions

All "Adjusted" data items have had the following adjustments made: Added back: goodwill amortisation, provision for catastrophe reserves, IFRS derivatives & hedging,

IFRS impairments & IFRS interest expense Excluded: non recurring items, asset revals, property revals, appraisal value uplift, preference dividends & minority interests EPS = adjusted net profit / efpowa* ROA = adjusted ebit / average total assets ROA Banks/Insurance = adjusted net profit /average total assets ROE = adjusted net profit / average shareholders funds Gross cashflow = adjusted net profit + depreciation *equivalent fully paid ordinary weighted average number of shares All Reported numbers for Australian/NZ listed stocks are modelled under IFRS (International Financial Reporting Standards).

Recommendation proportions – For quarter ending 31 December 2010

AU/NZ Asia RSA USA CA EUR Outperform 46.38% 62.62% 52.17% 44.99% 67.57% 50.90% (for US coverage by MCUSA, 13.59% of stocks covered are investment banking clients)

Neutral 37.68% 18.58% 34.78% 50.61% 28.83% 35.48% (for US coverage by MCUSA, 15.22% of stocks covered are investment banking clients)

Underperform 15.94% 18.80% 13.04% 4.40% 3.60% 13.62% (for US coverage by MCUSA, 0.00% of stocks covered are investment banking clients)

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Industrials

Capital Goods Peter Steyn (Johannesburg) (2711) 583 2337 Jean-Michel Bélanger (Paris) (33 1) 7036 9601 Beat Füglistaller (Zurich) (41 44) 564 0225 Christian Cohrs (Frankfurt) (49 69) 50957 8015

Autos

Christian Breitsprecher (Frankfurt) (49 69) 50957 8014 Jens Schattner (Frankfurt) (49 69) 50957 8026

Transportation – Infrastructure

Paul Butler (London) (44 20) 3037 4450 Robert Joynson (London) (44 20) 3037 4240 Peter Steyn (Johannesburg) (2711) 583 2337 Markus Hesse (Frankfurt) (49 69) 50957 8019

Materials

Chemicals/Containers, Packaging/Paper & Forest Products, Construction Materials

David Smith (Johannesburg) (2711) 583 2248 Peter Steyn (Johannesburg) (2711) 583 2337 Christian Faitz (Frankfurt) (49 69) 50957 8017 Jürgen Reck (Frankfurt) (49 69) 50957 8024

Global Metals & Mining

Michael Bogusz (London) (44 20) 3037 4359 Sergei Stephantsov (London) (44 20) 3037 2142 Justin Froneman (Johannesburg) (2711) 583 2293 Avishkar Nagaser (Johannesburg) (2711) 583 2280 Gareth Neilson (Johannesburg) (2711) 583 2318 Kieran Daly (Johannesburg) (2711) 583 2208 Peter Metzger (Frankfurt) (49 69) 50957 8023

Pharmaceuticals

Peter Düllman (Frankfurt) (49 69) 50957 8016 Claudia Lakatos (Frankfurt) (49 69) 50957 8022 Aadil Omar (Johannesburg) (2711) 583 2305 Christian Peter (Zurich) (41 44) 564 0226 Carri Duncan (Zurich) (41 44) 564 0224

Real Estate

Property Trusts & Developers Leon Allison (Johannesburg) (2711) 583 2209 Alex Moss (London) (44 20) 3 037 4086 Sven Janssen (Frankfurt) (49 69) 50957 8020 Mario Davatz (Zurich) (41 44) 564 0223

TMET

Telecommunications

Guy Peddy (London) (44 20) 3037 4509 Martin Dullaart (Johannesburg) (2711) 583 2322

Media

Tim Nollen (London) (44 20) 3037 4524 Martin Dullaart (Johannesburg) (2711) 583 2322

TMET – cont

Technology/IT/Internet

Nicholas von Stackelberg (Frankfurt) (49 69) 50957 8027 Marcus Sander (Frankfurt) (49 69) 50957 8025 Marco Zeidler (Frankfurt) (49 69) 50957 8029 Jean-Michel Bélanger (Paris) (33 1) 7036 9601

Utilities

Shai Hill (London) (44 20) 3037 4232 Stephen Flynn (London) (44 20) 3037 4227 Peter Gladkow (London) (44 20) 3037 4090 Atallah Estephan (London) (44 20) 3037 4356 Matthias Heck (Frankfurt) (49 69) 50957 8018

Commodities & Precious Metals

Jim Lennon (London) (44 20) 3037 4271 Max Layton (London) (44 20) 3037 4273 Colin Hamilton (London) (44 20) 3037 4061 Kona Haque (London) (44 20) 3037 4334

European Macro Group

Economics Daniel McCormack (Europe) (852) 3922 4073

Strategy Matthias Jörss (Frankfurt) (49 69) 50957 8021 Ralf Zimmermann (Frankfurt) (49 69) 50957 8030 Franco Busetti (Head of Strategy SA) (2711) 583 2205

Quantitative Gurvinder Brar (London) (44 20) 3037 4036 Christian Davies (London) (44 20) 3037 4037 Andy Moniz (London) (44 20) 3037 4039 James Murray (London) (44 20) 3037 1976 Adam Strudwick (London) (44 20) 3037 4038 Hannes Uys (Johannesburg) (2711) 583 2281 George Ssali (Johannesburg) (2711) 583 2364

Find our research at

Macquarie: www.macquarie.com.au/research

Thomson: www.thomson.com/financial

Reuters: www.knowledge.reuters.com

Bloomberg: MAC GO

Factset: http://www.factset.com/home.aspx

CapitalIQ www.capitaliq.com

TheMarkets.com www.themarkets.com

Contact Gareth Warfield for access (612) 8232 3207

Email addresses

[email protected]

eg. [email protected]

Equities

Stevan Vrcelj (Global Head) (612) 8232 5999 Duarte Da Silva (Johannesburg) (2711) 583 2000

UK Trading

Lloyd Smith (London) (44 20) 3037 4741 Julian Parmenter (London) (44 20) 3037 4826 Thorsten Ackermann (London) (44 20) 3037 4908 David Gill (London) (44 20) 3037 4980 Colin Reed (London) (44 20) 3037 4982 Harry Grist (London) (44 20) 3037 4950 Robert Tappin (London) (44 20) 3037 4827 Wayne Drayton (London) (44 20) 3037 4980 Andrew Vernik (London) (44 20) 3037 4818

UK Sales Trading Barbara Hantusch (London) (44 20) 3037 4910 Greg Hill (London) (44 20) 3037 4757 Drew Hendrickson (London) (44 20) 3037 4784 Joanne Mowatt-Morris (London) (44 20) 3037 4970 Leon Cutler (London) (44 20) 3037 4820 James Buckley (London) (44 20) 3037 4750 Jim Dixon (London) (44 20) 3037 4949 Chris Wellesley (London) (44 20) 3037 4779 Daryl Bowden (London) (44 20) 3037 4973

US Sales Trading

Chris Reale (New York) (1 212) 231 2616 Robert Preziosi (New York) (1 212) 231 2503

EU Cash Sales

Charles Nelson (London) (44 20) 3037 4832 Richard Alderman (London) (44 20) 3037 4875 Sam Bygott-Webb (London) (44 20) 3037 4767 Luke Ahern (London) (44 20) 3037 4960 Ettore Catalogna (London) (44 20) 3037 4962 Trevor Griffiths (London) (44 20) 3037 4964 Adam Shapton (London) (44 20) 3037 4974 Dominic Watt (London) (44 20) 3037 4975 Robin Wrench (London) (44 20) 3037 4978 Amy Stephenson (London) (44 20) 3037 4785 Matthew Camacho (London) (44 20) 3037 4972 Ed Reekie (London) (44 20) 3037 4957 Jacob Potts (London) (44 20) 3037 4929 Charles Lesser (London) (44 20) 3037 4771 Tim de Mierry (London) (44 20) 3037 4927 Paul De Thierry (London) (44 20) 3037 4809 Karl Filbert (Frankfurt) (49 69) 50957 8651 Heinz-Gerd Vinken (Frankfurt) (49 69) 50957 8659 Alex Schumacher (Frankfurt) (49 69) 50957 8657 Daniel Friedmann (Frankfurt) (49 69) 50957 8652 Heiko Backman (Frankfurt) (49 69) 50957 8650 Juergen Benker (Munich) (49 89) 2444 31808 Robert Weller (Munich) (49 89) 2444 31813 Klaus Pfaller (Munich) (49 89) 2444 31810 Alex Vogel (Munich) (49 89) 2444 31812 Fritz Hopp (Munich) (49 89) 2444 31809

EU Cash Sales – cont

Marco Galfetti (Zurich) (41 44) 564 0221 Yves Monrique (Paris) (33) 178 423 827 Jean-Claude Bonnamy (Paris) (33) 178 423 819 Myriam Lam (Paris) (33) 178 423 821 Martin Pommier (New York) (1 212) 231 8054 Doug Stone (New York) (1 212) 231 2606 David Bain (New York) (1 212) 231 2542 John Macaskill (New York) (1 212) 231 6398 Mark McGregor (New York) (1 212) 231 8075 Jorg Hagenbuch (New York) (1 212) 231 8086 Will Allen (Boston) (1 617) 723 5348 David Bain (San Francisco) (1 415) 762 5008

EMEA Derivative/DD1 sales

Steven Cowcher (London) (44 20) 3037 4707 Esmail Afsah (London) (44 20) 3037 4783

South Africa Sales

Franco Lorenzani (Johannesburg) (2711) 583 2014 Jessie Ushewokunze (Johannesburg) (2711) 583 2378 William Ridge (Johannesburg) (2711) 583 2060 Sherryl Roberts (London) (44 20) 3037 4030 Roland Wood (Cape Town) (2721) 813 2611 Nazmeera Moola (Cape Town) (2721) 813 2725 Darrin Blumenthal (New York) (1 212) 231 2562 Russell Fryer (New York) (1 212) 231 2504

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