InterOil Corp. LNG development offers outsized IRRs

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1 GLOBAL IOC US Price 2 Feb 11 Outperform US$ month target US$ month TSR % Valuation - DCF (WACC 12.0%) US$ GICS sector Energy Market cap US$m 3, day avg turnover US$m 29.5 Number shares on issue m Investment fundamentals Year end 31 Dec 2009A 2010E 2011E 2012E Revenue m , , ,300.5 EBIT m Reported profit m Adjusted profit m EPS adj US$ EPS adj growth % nmf PER adj x Total DPS US$ Total div yield % ROA % ROE % EV/EBITDA x Net debt/equity % P/BV x Source: FactSet, Macquarie Research, February 2011 (all figures in USD unless noted) 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 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 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 Capital (Europe) Ltd Jason Gammel jason.gammel@macquarie.com Macquarie Capital (USA) Inc John Nelson john.c.nelson@macquarie.com Matthew Lipton matthew.lipton@macquarie.com 3 February 2011 Please refer to the important disclosures and analyst certification on page 2 and the inside back cover of this document, or on our website

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 Company profile is an integrated energy company with primary operations in Papua New Guinea. The company is pursuing the development of a condensate stripping facility and an LNG export facility to monetize their significant natural gas discoveries in the region. Current operations include a 36k bpd refinery in Port Moresby and a downstream distribution network. Interoil also holds exploration licenses on nearly 4m acres in Papua New Guinea. Fig 1 Major Papua New Guinea license holders Source: Oil Search Ltd., Macquarie Capital (USA), February 2011 Fig 2 IOC US vs S&P 500 Source: FactSet, Macquarie Capital (USA), February 2011 (all figures in USD unless noted) 3 February

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 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. 3 February

4 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. 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 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 Fig 3 Initial project sanctioning could pave the way for 7 mtpa by YE2017 Macquarie Forecast Development Schedule* Train MTPA & Total 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$11.38 InterOil 2014 CFPS estimate. Brownfield expansions should further enhance cash generation. Fig 4 Project profitability & expansion opportunities will generate significant FCF US$m 3,000 2,500 2,000 1,500 1, (500) (1,000) US$b (2) (4) Cum Project FCF (RHS) Annual Project FCF (LHS) Source: Company reports, Macquarie Research, February 2011 Greenfield 3 mtpa development worth a risked US$69/sh. We anticipate a FID by mid 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. 3 February

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 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 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, $1,222 30% $ $1,795 50% $ $1,603 50% $ Total $7,217 $5,151 3,833 3, /sh $145 $ 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. 3 February

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 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 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 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 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. 3 February

7 Remember The commercial to use agreements side comments InterOil in and their this LNG section jointventure entity have made over the last To insert year have side accelerated comments the automatically, development timeline highlight and text, should go to set the Templates, company and on pace for a insert mid-2011 side comment. FID. 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 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 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 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 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. 3 February

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 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%. 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$ bn. Our base case assumes the company puts in place 7 mtpa of capacity by the end of 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 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 30 th, 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. 3 February

9 Assuming a positive mid-2011 FID, all parties anticipate that first production will commence by late 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 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 agreement 2 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$32m of which would be for FEED costs) to build a 400 mmcf/d plant capable of extracting 9kbd. The original cost estimate also included spending for the drilling of several gas reinjection wells and related compression equipment. These reinjection wells are no longer needed as the CSP will be developed in conjunction with the start-up of the first LNG train. We estimate savings from this will approximate US$ m. 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 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 Please see the addendix for further details about the joint-venture ownership structure. 3 February

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 underconstruction are more than double the upfront cost expected on this project. The lower levels of capital investment give the operators a cost advantage over their peers and should allow for the project to be sanctioned without the signing of long-term off-take agreements. The return to InterOil is further enhanced by Liquid Niugini s agreement with Energy World which leaves the latter responsible for 2/3 of up-front development costs. Below we detail the assumptions used in our project development model. Further details can be found in the appendices. Upstream assumptions. We assume 10 wells will be necessary over the 25-year plant life to support 3 mtpa of capacity. All-in, we expect these 10 wells will recover 5.1 tcfe of resource, or ~500 bcfe each. In our expansion modelling, we assume each 2 mtpa plant will support ~2.7 tcf of delivered LNG over the facility s 25-year life. We assume condensate yields will average 22.5 bbls/mmcf of natural gas leading to the development of 60 mmboe of condensate. Prolific resource base requires low development investment. We assume 6 wells are used for the initial 3 mtpa development. It should be noted that 4 of these wells have already been drilled during the exploration and appraisal of the Elk and Antelope Fields. In addition to the 2 wells required before start-up, we assume 2 additional wells are drilled at 10 and 15 years of production. We model these wells at a gross cost of US$35m. All-in, we expect these 10 wells will recover 5.1 tcfe of resource, or ~500 bcfe each. Recovery rates in excess of 80%. In their Elk and Antelope resource assessment, GLJ Petroleum Consultants noted that due to the fields moderate to weak aquifer strength, gas saturation and anticipated production rates, field recoveries could approximate 83-87% of OGIP (average 86%). In the report, the Arun gas field in Indonesia was presented as a potential analog. Ultimate recoveries for the Arun field are anticipated to reach 94% OGIP. 3 February

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 bbls/mmcf), thus our forecasts may prove conservative. The current assumptions assume recovery of 60 mmbbls of condensate for each 2 mtpa train. CSP assumptions. We assume CSP expansions will be necessary for the start-up of trains 4 and 5. The company would ultimately like to see each upstream participant take a proportionate interest in the CSP; however a final ownership structure has yet to be determined. We currently assume the CSP will receive a ~US$20/bbl throughput margin which should yield ~12% IRR, excluding sunk FEED costs. CSP expansion opportunity. We assume CSP expansions will be necessary when throughput breaches 400 and 700 mmcf/d, which we currently anticipate will occur at the start-up of trains 4 and 5, respectively. We expect these expansions will carry a capital cost of approximately US$230m. The lower cost assumption for the brownfield expansion is because they benefit from pipelines and site clearing spent in the first development phase. CSP ownership structure. The definitive agreement between InterOil and Mitsui signed in August of 2010 set each partners interest in the project equal at 50%. The Papua New Guinea government retains the right to farm-in to 22.5% of the CSP project. The government has yet to express any intention to do so, thus we exclude their participation in the CSP in our forecasts. Mitsui also retains the right to convert their 50% investment into a 2.5% interest in the Elk and Antelope fields after mechanical completion of the plant. We assume Mitsui will exercise this option. As such, we have modelled CSP economics to reflect a 50/50 ownership structure during plant construction and for 100% economic benefit accruing to InterOil upon project start-up. We assume all CSP expansions are proportionately funded by the upstream contingent. CSP operating cost. We expect operating costs for the CSP will approximate US$14/bbl. In order to generate a 12% IRR, we expect the CSP will charge the upstream operators US$32.50/bbl. Should Mitsui elect not to swap their interest in the CSP project for a 2.5% interest in the Elk and Antelope Field, we understand that this charge could rise above US$50/bbl which would meaningfully alter our forecasts. Liquefaction assumptions. The agreement between Energy World s and Liquid Niugini Gas will see Energy World receive roughly 14.5% of LNG revenues over the initial 15-year term and 4.8% thereafter. The fee will be subject to agreed deductions and execution targets could increase or decrease the fee percentage Energy World is entitled to. The tolling fee to be charged by the liquefaction unit to the upstream operators has yet to be disclosed. We currently assume the tolling fee matches expected plant operating costs. Energy World fee. The agreement between Energy World s and Liquid Niugini Gas will see Energy World receive roughly 14.5% of LNG revenues over the initial 15-year term and 4.8% thereafter. The fee will be subject to agreed deductions, mainly Energy World paying their proportional share of LNG plant operating costs. The final agreement is expected to include timing and execution targets that could increase or decrease the fee percentage Energy World is entitled to. 3 February

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$20m. These numbers equate to US$ 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. 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 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 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 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 * 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. 3 February

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 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 After deducting underwriting costs we anticipate the company raised approximately US$265m. Proceeds are anticipated to be used to repay a high cost US$25m loan with Clarion Finanz, for CSP and LNG related facilities capex, and for general corporate purposes. Fig 8 Recent financing allows considerable flexibility US$m Assume additional US$75m of liquidity raised through project finance Includes anticipated payment from Mitsui for additional 2.5% Upstream interest (100) 1Q11 2Q11 3Q11 4Q11 1Q12 2Q12 3Q12 4Q12 1Q13 2Q13 3Q13 4Q13 Available Cash FCF Source: Company data, Macquarie Capital (USA), February 2011 Break-even gas price Our development model shows that InterOil would require a natural gas price of US$(0.84)/mmcf for the initial 2 mtpa project to return a 15% IRR. 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. 3 February

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 slope, while Macquarie estimates use a 14.0 slope. Source:, 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 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 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 Development Schedule* Train MTPA & Total InterOil Expansion Case Development Schedule Train MTPA & Total *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. 3 February

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 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, $1,222 30% $ $1,795 50% $ $1,603 50% $ Total $7,217 $5,151 3,833 3, /sh $145 $ Source: Company data, Macquarie Capital (USA), February February

16 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. 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 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 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. 3 February

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. High-impact resource discovery potential is leading to rising investment in this underexplored basin from major international and independent operators. 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 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 Highlands Fly Basin Platform Central Forelands Gulf of Papua Source: Oil Search Ltd., Macquarie Capital (USA), February February

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 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 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. Source:, 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 GLJ is a well respected independent evaluation consultant for the oil and gas industry that has been in operation since 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. 3 February

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 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:, 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. 3 February

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:, 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 3 February

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 bbls of condensate per mmcf. A horizontal extension was also completed on Antelope-2 so that the company could gain further reservoir understanding. 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. 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. 3 February

22 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. 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 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 km east of the Antelope field. Seismosaurus PPL 237. Seismosaurus is a Miocene aged limestone prospect located in the southwest corner of PPL 237. We expect additional seismic acquisition and interpretation will be necessary before the company proceeds with drilling at Seismosaurus, however note its potential as a possible oil play. Fig 16 Map of InterOil exploration inventory Bwata West & Bwata Elk & Antelope Wolverine Seismosaurus Source:, Macquarie Capital (USA), February February

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 The agreement stipulated that four of the wells would be located in PPL 238, 1 each in PPL 237 and PL 236 and for the final two to be stipulated by the owners. Four wells have already drilled (which included the Elk Antelope discovery). It should be noted the company has repurchased a portion of these interests. Also, we highlight that this working interest percentage is quoted prior to the government s right to take up to a 22.5% working interest. PNG Drilling Ventures Ltd. (PNGDV). InterOil has an agreement with PNGDV in which InterOil carries PNGDV s 6.75% interest in 4 wells. Two of these wells have already been drilled (Elk-1 and Elk-4a) and two remain. Further, the agreement gives PNGDV the right to participate in 16 wells after the first four for up to 5.75% at a cost of US$112.5k per 1% interest, subject to certain adjustments. PNG Energy Investors (PNGEI). PNGEI has the option to participate in 4.25% of exploration wells 9-24 on PPL 236, PPL 237 and PPL 238. Only 6 exploration wells have been drilled to date. PNGEI s terms for participation call for the company to pay US$112.5k per 1% interest, subject to certain adjustments. New rig will help speed drilling times The company recently secured a new rig (InterOil rig #3) that is expected to increase the efficiency of drilling operations and increase capabilities going forward. Unlike InterOil rig #2, the new rig is not constructed to be easily transportable by helicopter. As such we expect rig #3 will be deployed to the Elk and Antelope fields for appraisal well drilling while rig #2 will be used for future exploration activities. Rig #3 underwent modifications in late 2010 and early 2011 and we expect it will be deployed later this year. 3 February

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 capacity 3. 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 6 th note, Australian LNG outlook: Squeezing through the closing window for further details). With so many projects competing for a finite set of workers, wage inflation here is likely to outpace other regions. The shortage is so bad that a report by the Australian National Resource Sector Taskforce suggested that over the next 5 years the industry will face a shortfall of 36,000 tradespeople and 1,700 engineers. Beyond the overall shortage of skilled tradespeople, wages for these workers have also risen to compensate for the harsh and/or remote environments in which the projects often reside. With Australian LNG projects already sitting on the right-end of the cost-curve due, many have already begun to wonder what the industry can do to preserve returns. Canadian Oil Sands example. Wage inflation for craft labor is not a new challenge for major oil producers. Earlier this decade this same phenomenon played out in the Canadian Oil Sands industry. Similar to LNG projects, the oil sands are also large capital intensive investments that require a large number of skilled workers during the initial construction phase. As crude prices rose over the last decade, sanctioning of new oil sands projects increased. This put pressure on wages as the number of qualified workers is relatively inflexible over such a short-time period. Inevitably, project costs inflated and the break-even price required to base investment advanced ahead of prior industry norms. The Global Financial Crisis took the wind out of oil prices and caused Canadian operators to put decelerate investment, however the example serves as a useful reminder of how labor competition can impact project investment economics. Can modular LNG development offer a cost advantage? The basics of trade and technology diffusion seem to be coming together to help the industry solve this looming problem. Global manufacturers are looking to meet the craft labor shortages in places like Australia by providing a modular solution that requires fewer skilled laborers during construction. By moving the construction process back into a manufacturing facility, providers are able to take advantage of relative labor cost advantages, gain increased efficiencies from repeated tasks and eliminate any harsh and/or remote climate premium necessary to attract employees. The price paid for these gains is the loss of custom tailored facilities. So, is it worth it? Judging by the trend of escalating costs from non-modular projects and recent modular project announcements the answer seems to be indicating yes. And by a large margin. To be sure, project sanctioning is infrequent. Further, even when capital cost estimates are provided detail around allocation across the upstream, liquefaction and distribution segments is typically vague. But, the gap seems to be wide enough to give a definitive answer. 3 Source: Wood Mackenzie LNG Tool 3 February

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 USD/tonne 3,000 Forecast 2,500 2,000 1,500 1, InterOil (500) 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). 3 February

26 The company primarily aims to maximize diesel output from their low complexity refinery in Papua New Guinea. 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 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 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 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%. 3 February

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 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 Mine life extension plans are being evaluated, in which case the mine could be extended through February

28 Risks to investment The following risk factors may affect the company s ability to progress their development program or impact project economics Geopolitical uncertainty InterOil s operations are focused in the Independent State of Papua New Guinea. The country is an emerging economy with inadequate transportation infrastructure, poor education systems and a rugged terrain. Emerging countries may be more susceptible to political instability than more developed markets. The lack of integrated transportation and infrastructure networks along with the high level of resource investment in the country could constrain InterOil s ability to advance their LNG export and condensate stripping development project. Commercial arrangements are key to development timeline The company and their partners have signed either definitive or preliminary commercial agreements on which their counterparties may be relied for achieving key milestones or making important commitments in order for the LNG export and condensate stripping project to proceed. Until definitive agreements are signed, the company may have limited or no legal options to enforce these agreements. Further, should these partners fail to meet their obligations, the company may need to pursue other strategies in order to progress their project which may include, but is not limited to, raising capital or selling down their ownership interest in order to fund these development activities. Also, counterparties may have outside interests that do not align with InterOil or their partners. Access to capital markets We currently expect the company has adequate capital resources in which to meet the funding requirements of their development projects. If development costs rise above our expectation, the company chooses an alternate or expanded development strategy and may need to access capital markets. Currently we assume the company will raise US$75m of project finance in order to meet spending commitments before first production. Foreign currency fluctuations The company conducts certain business operations in the currency of Papua New Guinea, the Kina. As such, the company is subject to currency risk from both higher levels of operating costs as well as their ability to meet debt payments in US Dollars. Project execution and operational risk The company and its partners plan to develop and construct an LNG export and condensate stripping project which will require the coordination of suppliers, contractors and employees from planning through to first production. Further, high resource development activity in the region could produce bottlenecks and may force the company or its partners to compete for services which could delay current projected timelines or cause a rise in projected costs. Once sanctioned for use, the company will be responsible for running day-to-day operations of the LNG export and condensate stripping project. InterOil also operates a refinery in Papua New Guinea which is subject to operational risk. LNG markets The company currently has no off-take agreements signed for their LNG export project and may need to sell future cargoes into a spot pricing environment that is less robust than we have forecast. 3 February

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 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, 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 William J. Jasper III President & Chief Operating Officer William J Jasper III is President and Chief Operating Officer of the company. Mr. Jasper joined on August 30, 2006, and, as President, leads the refining and downstream business. Prior to joining InterOil, Mr. Jasper had worked for Chevron Pipe Line Company since 1974, serving in leadership and management capacities over facilities, pipelines and terminals. Prior to this role, Mr. Jasper served 4 years as Chairman of the West Texas LPG Partnership Board of Directors and was President and General Manager of Kenai Pipe Line Company in Alaska and the West Texas Gulf Pipeline in Texas. Christian M. Vinson Executive Vice President of Corporate Development and Government Affairs Christian M. Vinson is Executive Vice President of InterOil and head of Corporate Development. From 1995 to August 2006 he was Chief Operating Officer. Mr. Vinson joined the company from Petroleum Independent Exploration Corporation, a Houston, Texas based oil and gas exploration and production company. Before joining Petroleum Independent Exploration Corporation, Mr. Vinson was a manager with NUM Corporation, a Schneider company involved in mechanical and electrical engineering automation, in Naperville, Illinois where his responsibilities included the establishment of the company s first office in the United States. As InterOil s Chief Operating Officer, Mr. Vinson has responsibility for government and community relations and corporate development in Papua New Guinea. Mr. Vinson has worked with government and industry leaders in Papua New Guinea over the last ten years. Mr Vinson earned an Electrical and Mechanical Engineering degree from Ecole d Electricité et Mécanique Industrielles, Paris, France. 3 February

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 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 Prior to joining InterOil, since 2002, Wayne was employed by Marathon Oil Company as Joint Venture Manager, Equatorial Guinea, where he worked directly with production operations and major projects and on all communication with the State government and joint interest partners. From 1987 to 2002 Wayne was employed by CMS Oil & Gas Company where from 1999 to 2002 he held the position, Production Manager, Equatorial Guinea. Mr. Hamal holds a Bachelor of Science degree in Petroleum Engineering from the Colorado School of Mines. 3 February

31 Fig 19 financial summary Outperform TP = $121 Income statement - US$m E 2011E 2012E 2013E Macro assumptions E 2011E 2012E 2013E Upstream core earnings (14) (26) (21) (44) 103 WTI Oil (US$/bbl) Refining core earnings (4) (18) (20) (20) 65 US Natural Gas (US$/mcf) Liquefaction core earnings (1) (1) LNG Spot (US$/mcf) Downstream core earnings (10) (10) (5) (5) 27 Production assumptions E 2011E 2012E 2013E Total Corporate charges (12) (2) 0 (17) (12) Oil/liquids (k bbl/d) Operational earnings Natural Gas (mmcf/d) Special items (A/T) (183) Total Production (boe) Reported earnings Upstream Resource & NPV Summary Per share E 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 $2,597 0% $2,597 1,632 1, Adjusted Earnings $ 0.49 $ 0.32 $ 0.81 $ 0.81 $ $1,222 30% $ Cash Flow from Operations $ 1.09 $ (0.12) $ 1.26 $ 1.26 $ $1,795 50% $ Dividend $ - $ - $ - $ - $ - 5 $1,603 50% $ Total $7,217 $5,151 3,833 3, Cash flow US$m E 2011E 2012E 2013E /sh $145 $ Net income 6 (7) DD&A Downstream Valuation Changes in working capital (13) (47) Refining EBITDA $ 84 Operating cash flow 44 (5) Multiple 7.0 Capital Expenditures (104) (130) (167) (182) (133) Multiple Value ($m) $ 591 Major Acquisitions Proceeds from Asset Sales Distribution EBITDA $ 32 Cash from investing (86) (91) (139) (182) 114 Multiple 4.5 Cash Dividends Paid Multiple Value ($m) $ 142 Issuance/Reduction of Debt, Net (53) Sale/Repurchase of Stock, Net Downstream Value $ 733 Cash from financing (14) 56 4 /sh $15 Balance Sheet US$m E 2011E 2012E 2013E Base Case Assumptions Cash and Cash Equivalents Dil Shs Outstanding (m) 50 Total Debt Discount Rate 12% Shareholders' Equity ,163 Long-term Oil price ($/bbl) $ 90 Total Capitalization ,356 LNG slope 0.14 Financial Ratios E 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 Source: Company reports, Macquarie Research, February February

32 3 February Fig 20 Macquarie forecast Liquid Niugini Gas Ltd. LNG Development schedule Train MTPA & Total *First year each train will run at full capacity Source: Company reports, Macquarie Research, February 2011 Fig 21 Liquid Niugini Gas Ltd. All-Party LNG Development & CSP economic analysis FCF (US$m) Train 1 & 2 - MTPA 1 & 2 Upstream - (61) (86) CSP - (55) (138) (68) Liquefaction - (303) (303) (270) Total - (419) (526) (152) NPV $4,151 IRR 50% Train 3 - MTPA 3 - (153) (154) (23) NPV $2,284 IRR 71% Train 4 - MTPA 4 & 5 - (213) (298) (56) NPV $2,083 IRR 52% Train 5 - MTPA 6 & 7 - (213) (298) (56) NPV $2,083 IRR 52% Total FCF - (419) (679) (306) ,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 Source: Company reports, Macquarie Research, February 2011

33 3 February Fig 22 Liquid Niugini Gas Ltd. LNG Development - All-Party Upstream economic analysis (first 2 mtpa of capacity only) Natural gas production (mmcfd) - LNG 3, Condensate production (mbd) Total production (kbpd) Total Contracted volumes % of volumes contracted 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% Uncontracted volumes LNG deliveries (mmtpa) LNG deliveries (mmcfd) 2, LNG pricing formula (contract) LNG price (uncontracted) Wellhead condensate price LNG Revenues 30, ,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 ,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, Other Revenues Total Revenue ,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 rd Party Gas Purchases LOE Condensate Plant Operating Expenses Royalty LNG Plant operating expenses Shipping fees 1, Other - Total Cash Expenses 5, Depreciation (for tax calc) Cash flow before taxes & C&E 27, ,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, Operational cash flow 19, Capital expenditures Free cash flow 18,920 - (61) (86) NPV $4,173 IRR 163% Source: Company reports, Macquarie Research, February 2011

34 3 February Fig 23 Liquid Niugini Gas Ltd. LNG Development - Energy World economic analysis (first 2 mtpa of capacity only) Total delivered LNG (mmcfd) Initial Contract Period (yrs) % 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% Less related costs Total Net EWC payment Liquefaction Opex $ DD&A Taxes Forecast EWC CFO Forecast EWC Capex (303) (303) (303) Net EWC Cashflow - (303) (303) (271) IRR 11.1% 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) NG Production Condensate production (mbd) Revenue $ CSP Opex $ DD&A Taxes Forecast CSP CFO Forecast CSP Capex (55) (138) (83) Net CSP Cashflow - (55) (138) (68) Net Income IRR 12.1% 7.6% Source: Company reports, Macquarie Research, February 2011

35 3 February Fig 25 Liquid Niugini Gas Ltd. LNG Development 1 mtpa plant capacity expansion economic analysis (assuming Energy World funded) Year LNG sales (mmtpa) 25% Total delivered LNG (mmcfd) 1, LNG plant input (mmcfd) Natural gas production (mmcfd) - LNG Condensate production (mbd) Total production (kbpd) Contracted volumes (mmtpa) 0% Uncontracted volumes LNG pricing formula (contract) LNG price (uncontracted) Wellhead condensate price LNG Revenues EWC Payment (25) (100) (100) (100) (100) (100) (100) (100) (100) (100) (100) (100) Net LNG Revenues Condensate Revenues Other Revenues Total Revenue LOE $ Condensate Plant Operating Expenses $ Royalty LNG Plant operating expenses $ Shipping fees $ Other - Total Cash Expenses 2, Upstream DD&A $ CSP DD&A Liquefaction DD&A $ Total DD&A (for tax calc) Cash flow before taxes & C&E 16, Income taxes 30% Operational cash flow 11, Upstream Capital expenditures $ CSP Capital expendiutres $ Liquefaction Facility Capital expenditures $ Liquefaction Site Capital expenditures $ Total Capital expenditures $ Free cashflow 11,033 - (63) (148) NPV $2,103 IRR 97% Expansion from 2mtpa to 3 mtpa Free cashflow - (1) (3) NPV $2,279 IRR 1026% Source: Company reports, Macquarie Research, February 2011

36 3 February Fig 26 Liquid Niugini Gas Ltd. LNG Development 1 mtpa plant capacity expansion economic analysis (assuming Upstream partner-funded) Year LNG sales (mmtpa) 25% Total delivered LNG (mmcfd) 1, LNG plant input (mmcfd) Natural gas production (mmcfd) - LNG Condensate production (mbd) Total production (kbpd) Contracted volumes (mmtpa) 0% Uncontracted volumes LNG pricing formula (contract) LNG price (uncontracted) Wellhead condensate price LNG Revenues Condensate Revenues Other Revenues Total Revenue LOE $ Condensate Plant Operating Expenses $ Royalty LNG Plant operating expenses $ Shipping fees $ Other - Total Cash Expenses 2, Upstream DD&A $ CSP DD&A Liquefaction DD&A $ Total DD&A (for tax calc) Cash flow before taxes & C&E 18, Income taxes 30% Operational cash flow 12, Upstream Capital expenditures $ CSP Capital expendiutres $ Liquefaction Facility Capital expenditures $ Liquefaction Site Capital expenditures $ Total Capital expenditures $ 1, Free cashflow 11,830 - (213) (298) (56) NPV $2,101 IRR 52% Source: Company reports, Macquarie Research, February 2011

37 Appendices Fig 27 InterOil IRR sensitivity to the first 2 mtpa LNG facility & CSP development Change in crude px $ 70 $ 80 $ 90 $ 100 $ % $ (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 % 125.5% 136.9% 147.7% 155.6% Price % 130.8% 142.5% 153.6% 161.2% % 136.0% 148.0% 159.3% 166.7% Change in crude px $ 70 $ 80 $ 90 $ 100 $ % $ (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 $ $ $ $ % 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% Source: Company reports, Macquarie Research, February 2011 Fig 28 Liquid Niugini Gas Ltd. (LNG joint-venture) ownership structure 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 *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 Source: Company reports, Macquarie Research, February February

38 Fig 29 Condensate stripping facility ownership structure Condensate Stripping Facility 50%/(38.75%) * Mitsui & Co., Ltd. 50%/(38.75%) * Papua New Guinea State Government & Local Land Owners (22.5%) * *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. Source: Company reports, Macquarie Research, February 2011 Fig 30 Elk-Antelope field ownership interests 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 Source: Company reports, Macquarie Research, February February

39 Fig 31 InterOil Papua New Guinea exploration summary Source:, Macquarie Research, February 2011 Fig 32 InterOil Papua New Guinea exploration well map Source:, Macquarie Research, February February