Which one of you SM's will negotiate a friendly take-over of IOC 100%?
Benefits to you are as follows:
1) Abbregate enough nattie for 12Mtpa LNG production overnight.
2) Acquisition of a company with an intact Project Agreement, project only needs funding and ground breaks within weeks.
3) Social mapping, engineering, surveying, land acquisitions are all complete or identified
4) LNG specific labor and construction equipment are available on island immediately
5) Unmatched exploration upside in a proven hydrocarbon basin
6) PRL 15 gas cost is $.12 at the LNG plant while PNG LNG is ~ $7Mcf
7) Remedy is to buy IOC for $3.5/M or $450 pps, add liquefaction costs of $3/M and your produced LNG costs are still LESS than PNG LNG dry gas cost.
8) You have researched the resource and if you are willing to bid for a 30% chunk of 1 PRL it is to your greatest advantage to buy the whole operation.
9) There is an eager PNG Gov't seeking a SM to bring credibility to their nation and this resource.
10) Your shareholders will benefit greatest with an outright purchase.
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Moving toward the front of the LNG development queue. The capital costs of Interoil‟s LNG development rank the lowest of all currently proposed or under-construction projects on both an absolute and per-unit basis. The lower cost structure makes the project price competitive and we expect it will allow early market penetration.
Break-even gas price Our development model shows that InterOil would require a natural gas price of US$(0.84)/mmcf for the initial 2 mtpa project to return a 15% IRR. The negative price is due to the revenue generated by stripping liquids. Liquid Niugini Gas has estimated that excluding this subsidy, the project would still only require a US$0.70/mmcf FOB natural gas price to generate a 12% IRR.
Gulf LNG gas price Gulf LNG Natural Gas price of US $.12/mmcf, with condensate subsidy, for a 12% IRR. PNG LNG $7+/mmcf
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.
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.
Economics of LNG and CSP (EWC base plan, but you get the picture) We forecast the complete project IRR is ~50%, which compares quite favourably to proposed or under-construction Greenfield projects mostly in the mid-teens.
~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.
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.
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.
Independent resource assessment (FEB. 2011, mind you) InterOil secured GLJ Petroleum Consultants Ltd. (GLJ) to provide an independent resource assessment of the Elk and Antelope fields. The effective date of the analysis was year-end 2009 and a complete report was returned to the company in February of 2010. GLJ is a well respected independent evaluation consultant for the oil and gas industry that has been in operation since 1972. The company has provided expert analysis and critical opinions for a broad array of client needs, including but not limited to financing, mergers, acquisitions, divestitures and public reporting. Roger Mahoney, the geophysicist retained by GLJ to provide the analysis, has over 35 years of experience in seismic acquisition, processing and interpretation. GLJ‟s conclusion was that the fields hold more than 11 tcf of OGIP and 9 tcf of recoverable wet gas. Condensate recoveries were estimated at 157 mmboe.
It is our understanding that the analysis performed by GLJ was completed with well data through drill stem test (DST) #1 at Antelope-2. Since that time InterOil has completed at least 6 more drill stem tests and a completed a 1,700 ft horizontal lateral. Further, these later test results have been very encouraging. Specifically, in September 2010 InterOil announced that during the horizontal leg the condensate-to-gas ratio stabilized at 24-27.7 bbls of condensate per mmcf. This observation is roughly 60% higher than the levels observed in DST #1, and may support positive revisions to prior estimates. InterOil has not provided an interim resource assessment update which take into account these results. Our resource development model estimates a slightly higher level of recoverable resource as our analysis takes into account more recent drilling results. We estimate 9.4 tcf of gross gas resource will be developed (+15% versus GLJ estimate) and expect condensate recoveries may approach 210 mmbbls (+33% versus GLJ estimate).
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. |
