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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)
Macquarie Research InterOil Corp.
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$2.5b.
Project development offers outsized IRRs. We forecast the complete project IRR is ~50%,
which compares quite favourably to proposed or under-construction Greenfield projects
mostly in the low- to mid-teens. We estimate InterOil’s IRR will be:
~135% on first 2 mtpa investment and related condensate stripping facilities
~1,025% for a 1 mtpa expansion to immediately follow the greenfield investment
~50% for each internally funded 2 mtpa expansion.
Our development model shows that InterOil would require a natural gas price of
US$(0.84)/mmcf for the initial 2 mtpa project to return a 15% IRR. 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.
Macquarie Research InterOil Corp.
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.
Macquarie Research InterOil Corp.
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
Source: Company reports, Macquarie Capital (USA), February 2011
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:
~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.
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
Macquarie Research InterOil Corp.
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
Source: Company reports, Macquarie Capital (USA), February 2011
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
Macquarie Research InterOil Corp.
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.
Macquarie Research InterOil Corp.
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%.
Macquarie Research InterOil Corp.
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.
Macquarie Research InterOil Corp.
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.
Macquarie Research InterOil Corp.
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.
Macquarie Research InterOil Corp.
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.
Macquarie Research InterOil Corp.
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$25m loan with Clarion Finanz, for CSP and LNG
related facilities capex, and for general corporate purposes.
Fig 8 Recent financing allows considerable flexibility
Source: Company data, Macquarie Capital (USA), February 2011
Break-even gas price
Our development model shows that InterOil would require a natural gas price of
US$(0.84)/mmcf for the initial 2 mtpa project to return a 15% IRR. 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.
Macquarie Research InterOil Corp.
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
Source: Company data, Macquarie Capital (USA), February 2011
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
Macquarie Research InterOil Corp.
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
Source: Company data, Macquarie Capital (USA), February 2011
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
Macquarie Research InterOil Corp.
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.
Macquarie Research InterOil Corp.
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.
Macquarie Research InterOil Corp.
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.
Macquarie Research InterOil Corp.
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
Source: InterOil Corp., Macquarie Capital (USA), February 2011
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.
Macquarie Research InterOil Corp.
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
Source: InterOil Corp., Macquarie Capital (USA), February 2011
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.
Cost estimate: US$35m
Macquarie Research InterOil Corp.
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.
Cost estimate: US$45m
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.
Macquarie Research InterOil Corp.
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
Source: InterOil Corp., Macquarie Capital (USA), February 2011
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.
Macquarie Research InterOil Corp.
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.
Macquarie Research InterOil Corp.
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
Macquarie Research InterOil Corp.
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
Macquarie Research InterOil Corp.
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.
Macquarie Research InterOil Corp.
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.
Macquarie Research InterOil Corp.
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.
Macquarie Research InterOil Corp.
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.
Macquarie Research InterOil Corp.
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.
Macquarie Research InterOil Corp.
3 February 2011 31
Fig 19 InterOil Corp. financial summary
Source: Company reports, Macquarie Research, February 2011
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$/mcf) 8.50 11.19 11.95 13.82 14.29
Downstream core earnings (10) (10) (5) (5) 27 Production assumptions 2009 2010E 2011E 2012E 2013E
Total Corporate charges (12) (2) 0 (17) (12) Oil/liquids (k bbl/d) 0 0 0 0 1
Operational earnings 20 15 40 41 139 Natural Gas (mmcf/d) 0 0 0 0 39
Special items (A/T) 41 58 46 85 (183) Total Production (boe) 0 0 0 0 8
Reported earnings 20 15 40 41 139
Upstream Resource & NPV Summary
Per share 2009 2010E 2011E 2012E 2013E Risk Risked Net Risked Resource
Basic EPS 0.15$ (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. $121
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Fig 20 Macquarie forecast Liquid Niugini Gas Ltd. LNG Development schedule
Source: Company reports, Macquarie Research, February 2011
Fig 21 Liquid Niugini Gas Ltd. All-Party LNG Development & CSP economic analysis
Source: Company reports, Macquarie Research, February 2011
Train MTPA 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
1 & 2 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0
3 1.0 1.0 1.0 1.0 1.0 1.0 1.0
4 2.0 2.0 2.0 2.0 2.0
5 2.0 2.0 2.0 2.0
Total 7.0 - - - 2.0 3.0 3.0 5.0 7.0 7.0 7.0
*First year each train will run at full capacity
FCF (US$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)
Source: Company reports, Macquarie Research, February 2011
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 $4,173
IRR 163%
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Fig 23 Liquid Niugini Gas Ltd. LNG Development - Energy World economic analysis (first 2 mtpa of capacity only)
Source: Company reports, Macquarie Research, February 2011
Fig 24 Liquid Niugini Gas Ltd. LNG Development – condensate stripping plant (CSP) economic analysis (first 2 mtpa of capacity only)
Source: Company reports, Macquarie Research, February 2011
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025
Total delivered LNG (mmcfd) - - - 73 291 291 291 291 291 291 291 291 291 291 291 291
Initial Contract Period (yrs) 15 - - - 1 2 3 4 5 6 7 8 9 10 11 12 13
% of LNG throughput for EWC <15 yr 14.5% 14.5% 14.5% 14.5% 14.5% 14.5% 14.5% 14.5% 14.5% 14.5% 14.5% 14.5% 14.5% 14.5% 14.5% 14.5% 14.5%
EWC Payment >15 yr 4.8% - - - 44 175 175 175 175 175 175 175 175 175 175 175 175
Less related costs - - - 1 5 5 5 5 5 5 5 5 5 5 5 5
Total Net EWC payment - - - 42 170 170 170 170 170 170 170 170 170 170 170 170
Liquefaction Opex 0.33$ - - - 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%
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Fig 25 Liquid Niugini Gas Ltd. LNG Development – 1 mtpa plant capacity expansion economic analysis (assuming Energy World funded)
Source: Company reports, Macquarie Research, February 2011
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 pricing formula (contract) 11.99 11.99 11.99 11.99 11.99 11.99 11.99 11.99 11.99 11.99 11.99 11.99 11.99 11.99 11.99 11.99
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 95.13 95.13 95.13 95.13 95.13 95.13 95.13 95.13 95.13 95.13 95.13 95.13 95.13 95.13 95.13 95.13
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 $2,279
IRR 1026%
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Fig 26 Liquid Niugini Gas Ltd. LNG Development – 1 mtpa plant capacity expansion economic analysis (assuming Upstream partner-funded)
Source: Company reports, Macquarie Research, February 2011
Year 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15
LNG sales (mmtpa) 25% 0.25 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00
Total delivered LNG (mmcfd) 1,342 - - - 36 146 146 146 146 146 146 146 146 146 146 146
LNG plant input (mmcfd) - - - 42 167 167 167 167 167 167 167 167 167 167 167
Natural gas production (mmcfd) - LNG - - - 42 167 167 167 167 167 167 167 167 167 167 167
Condensate production (mbd) 30 1 4 4 4 4 4 4 4 4 4 4 4
Total production (kbpd) - - - 8 32 32 32 32 32 32 32 32 32 31 31
Contracted volumes (mmtpa) 0% - - - - - - - - - - - - - - -
Uncontracted volumes - - - 42 167 167 167 167 167 167 167 167 167 167 167
LNG pricing formula (contract) 11.99 11.99 11.99 11.99 11.99 11.99 11.99 11.99 11.99 11.99 11.99 11.99 11.99 11.99 11.99 11.99
LNG price (uncontracted) 11.34 11.34 11.34 11.34 11.34 11.34 11.34 11.34 11.34 11.34 11.34 11.34 11.34 11.34 11.34 11.34
Wellhead condensate price 95.13 95.13 95.13 95.13 95.13 95.13 95.13 95.13 95.13 95.13 95.13 95.13 95.13 95.13 95.13 95.13
LNG Revenues - - - 173 691 691 691 691 691 691 691 691 691 691 691
Condensate Revenues - - - 33 130 130 130 130 130 130 130 130 130 126 123
Other Revenues
Total Revenue - - - 205 821 821 821 821 821 821 821 821 821 817 813
LOE 0.66$ - - - 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 $2,101
IRR 52%
Macquarie Research InterOil Corp.
3 February 2011 37
Appendices
Fig 27 InterOil IRR sensitivity to the first 2 mtpa LNG facility & CSP development
Source: Company reports, Macquarie Research, February 2011
Fig 28 Liquid Niugini Gas Ltd. (LNG joint-venture) ownership structure
Source: Company reports, Macquarie Research, February 2011
Change in crude px
70$ 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
Macquarie Research InterOil Corp.
3 February 2011 38
Fig 29 Condensate stripping facility ownership structure
Source: Company reports, Macquarie Research, February 2011
Fig 30 Elk-Antelope field ownership interests
Source: Company reports, Macquarie Research, February 2011
*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
Macquarie Research InterOil Corp.
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
Source: InterOil Corp., Macquarie Research, February 2011
Macquarie Research InterOil Corp.
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$
Macquarie Research InterOil Corp.
3 February 2011 41
Fig 34 InterOil Napa Napa Refinery schematic
Source: InterOil Corp., Macquarie Research, February 2011
Fig 35 InterOil Napa Napa Refinery schematic with potential expansion
Source: InterOil Corp., Macquarie Research, February 2011
Macquarie Research InterOil Corp.
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)
Company Specific Disclosures: As announced on November 4, 2010, Macquarie Group managed or co-managed a public offering of securities on behalf of InterOil Corporation. Within the last 12 months, Macquarie Group has received compensation for investment advisory services from InterOil Corporation. Important disclosure information regarding the subject companies covered in this report is available at www.macquarie.com/disclosures.
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The Research Distribution Policy of Macquarie Capital Markets Canada Ltd is to allow all clients that are entitled to have equal access to our research. United Kingdom: In the United Kingdom, research is issued and distributed by Macquarie Capital (Europe) Ltd, which is authorised and regulated by the Financial Services Authority (No. 193905). Germany: In Germany, research is issued and distributed by Macquarie Capital (Europe) Ltd, Niederlassung Deutschland, which is authorised and regulated in the United Kingdom by the Financial Services Authority (No. 193905). France: In France, research is issued and distributed by Macquarie Capital (Europe) Ltd, which is authorised and regulated in the United Kingdom by the Financial Services Authority (No. 193905). Hong Kong: In Hong Kong, research is issued and distributed by Macquarie Capital Securities Ltd, which is licensed and regulated by the Securities and Futures Commission. Japan: In
Macquarie Research InterOil Corp.
3 February 2011 43
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Julian Wentzel (Johannesburg) (2711) 583 2202 Sreedhar Mahamkali (London) (44 20) 3037 4016 Vincent Hamel (Paris) (33 1) 7036 9607
Consumer Discretionary
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Julian Wentzel (Johannesburg) (2711) 583 2202 Stephen Carrott (Johannesburg) (2711) 583 2211 Sreedhar Mahamkali (London) (44 20) 3037 4016 Rebecca Lay (London) (44 20) 303 74468 Robert Joyce (London) (44 20) 3037 4355 Vincent Hamel (Paris) (33 1) 7036 9607
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Alternative Energy
Shai Hill (Europe) (44 20) 3037 4232 Robert Schramm (Europe) (44 20) 3037 4559 Kasper Larsen (London) (44 20) 3037 4091
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Diversified Financials
Neil Welch (London) (44 20) 3037 4272 William Howlett (London) (44 20) 3037 4196
Banks Edward Firth (Europe) (44 20) 3037 4077 Alessandro Roccati (London) (44 20) 3037 4254 Dave Johnston (London) (44 20) 3037 4525 Benjie Creelan-Sandford (London) (44 20) 3037 4081 Thomas Stoegner (London) (44 20) 3037 4532 Carsten Werle (Frankfurt) (49 69) 50957 8028
Insurance Chris Esson (London) (44 20) 3037 4277 Hadley Cohen (London) (44 20) 3037 4078 William Hardcastle (London) (44 20) 3037 4195
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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
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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
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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
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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
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Economics Daniel McCormack (Europe) (852) 3922 4073
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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
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Equities
Stevan Vrcelj (Global Head) (612) 8232 5999 Duarte Da Silva (Johannesburg) (2711) 583 2000
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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