Royal Dutch Shell
The author makes a big deal out of Royal Dutch Shell (NYSE: RDS.A) not being allowed into InterOil's data room, insinuating that InterOil must have something to hide. Pure garbage. Here are the facts. InterOil has allowed every qualified company to have full access to the data room after the potential bidder signs a non-disclosure agreement (NDA) that contains a standstill provision.
In layman's terms, an NDA with a standstill requires the signee to both not disclose information received in the data room and it prohibits the signee from buying InterOil common stock in the open market. Sources close to the sell-down process indicate Shell (unlike numerous other supermajor energy companies) remains unwilling to sign the NDA and standstill. Why could this be? Maybe Shell does not need access to the data room to get the information in it? In 2011 Shell and Petromin PNG Holdings (a PNG state-owned company that holds PNG's interest in all projects undertaken in the Energy industry in PNG) signed a strategic alliance to analyze and pursue upstream hydrocarbon development in PNG. As part of InterOil's license agreement, PNG owns a 22.5% interest in all the resources InterOil develops. PNG's 22.5% is held and managed by Petromin. Petromin receives the seismic, aero-magnetic, gravity, and drilling and hydrocarbon analysis data directly from InterOil on the various resources. Hence, Shell (Petromin's partner) is already seeing much of the data on InterOil's resources through its Petromin relationship. Second, Shell recently lost out on its latest takeover attempt, Cove Energy PLC. Cove Energy is a natural gas play that owns, among other assets, 8.5% of a large offshore gas field off of Mozambique. Shell CEO Peter Voser recently signaled that Shell is actively looking for additional acquisitions.
Both Shell's CFO and CEO recently were quoted saying they have been in talks with InterOil. It would certainly make sense for Shell to buy up to 20% of InterOil's common stock in the open market before making an offer (at a substantial premium) for 100% of the company. Shell would not be able to buy InterOil common stock in the market if it signed the NDA which contains a standstill provision. Of course, all M&A is speculative, yet it seems like a logical reason for Shell to refuse to sign the NDA with the standstill provision. Shell walked away from the Cove Energy takeover attempt empty handed. If Shell was to buy 20% of InterOil's common stock and it intends to attempt to acquire 100% of InterOil, then Shell is guaranteed of a positive outcome. If Shell loses the bidding war, Shell will still make a handsome profit on the shares it owns. If Shell is successful in ultimately acquiring InterOil, Shell dramatically lowers its total cost of the takeover by buying 20% of InterOil's shares well below the final takeout price. Lastly, contrary to the erroneous claims in the previous article, InterOil has NEVER promised a deal with any company and InterOil has certainly NEVER "basically promised a HUGE deal with Shell." I challenge the author to provide a single piece of verifiable data to support this statement.
Condensate Stripping Plant
Over $33M was spent on front-end engineering and design (FEED) and was entirely funded by InterOil's likely partner, Mitsui & Co., Ltd. The FEED for the condensate stripping plant (CSP) was completed in late 2011. The author quotes someone purporting to be a hedge fund manager claiming the $33M of CSP FEED expenses are "comically low" and then goes on to make a reference to "dry hole blowback." Claiming $33M for FEED is comically low is just plain wrong. If anything, the FEED analysis was overly detailed and comprehensive. Perhaps this unnamed source can shed light on how he arrived at his conclusion?
Secondly, the oil and gas industry engineering experts I consulted have not heard of the term "dry hole blowback" in relation to a condensate stripping plant and concluded that term is meaningless. Perhaps the anonymous hedge fund manager was referring to "dry gas breakthrough?" Dry gas breakthrough is a condition that can occur in a reservoir during a stand-alone condensate stripping project in which dry gas is reinjected into the reservoir. The reservoir could eventually reach a point where the dry gas being reinjected clears a direct path back the wet gas take-point, which means you are recycling the same dry gas and recovering less condensate. Dry gas breakthrough was a reservoir modeling parameter factored into the economic analysis when InterOil was considering a stand-alone condensate stripping plant. However, this dynamic is moot. Since 2010 InterOil has been planning to start LNG production at the same time as the gas conditioning plant (condensate stripping), so there is no reinjection of dry gas planned and therefore there is no risk of dry gas breakthrough.
The author of the previous article further attempts to discredit InterOil by claiming the company does not have an SEC-compliant resource estimate. An informative response to this statement was written by "bonkthegrups" in the comment section of the same article. I quote…"IOC is a Canadian reporting issuer (the SEC isn't its principal regulator). Secondly, the Canadian regulations are extremely comprehensive and equally as rigorous as the SEC rules - read about NI-51-101 and the differences here. Note the main difference is the Canadian regs allow the use of forward contract prices, whereas the SEC requires a constant price. Another major benefit of the Canadian regs is they require independent evaluation - the SEC regs do not. Thirdly, GLJ is a top notch firm, with major clients like Suncor, and is also familiar with NI-51-101 so it makes sense to use them for annual filing requirements - the reports are required by law - a potential large LNG partner would likely use their own firm anyway." GLJ Petroleum Consultants is a world-class reservoir engineering company and works for some of the world's leading energy companies. Client list.
Further, the author of the previous negative article conveniently fails to mention that in addition to GLJ's official Elk/Antelope reservoir estimate of 8.6 tcf of gas (page 7), another reservoir estimate of Elk/Antelope was prepared by the ultra-conservative world-class firm Gaffney Cline. Gaffney Cline was hired in late 2011 by third parties (not InterOil) to provide another reservoir estimate as part of the deal process. All of the well data pertaining to Elk/Antelope used by both GLJ and Gaffney Cline for their respective analyses was produced by world-class third parties. InterOil did not generate any of the reservoir data used by either GLJ or Gaffney Cline. After reviewing all of the electric log data on Elk/Antelope from Schlumberger, the flow rates as measured by Weatherford and the analysis of the composition of the gas and condensate liquids from SGS. Gaffney Cline conservatively concluded that Elk/Antelope's reef reservoir contains 6.6 trillion cubic feet of gas…more than enough for InterOil's Gulf Project. Now let's further explain why the previous author's claims that InterOil's well are "non-commercial" are flat out wrong.
The previous author reasons that since companies drilled sporadically in the Eastern Papuan Basin in the 1950s and 1980s with limited success, there is no way that InterOil (albeit using modern state-of-the-art technology) could have found reefal formations in the Eastern Papuan Basin. Let's begin with some history and geology.
During the 1950s a number of wells were drilled in the Gulf Province. Seismic data collection was in its infancy and was not used in PNG during the 1950s. Prospects were generated by field mapping and surface anticlines (a convex fold in the topography) were drilled. By definition, without the use of seismic analysis, aero-magnetic and/or gravity data, drillers in the 1950s and 80s were merely guessing at what could lie beneath the surface. While these 1950s and 80s wells were not drilled in optimal locations and were not economic at the time (hard to be economic when natural gas was viewed as a nuisance back then and oil sold for $1-$2 per barrel in the 1950s), the older wells were noteworthy because: 1) the wells tested positively for hydrocarbons, both oil and gas, indicating an active hydrocarbon system is in place where a nearby source rock is of the right thermal maturity to generate both oil and gas, 2) they tested a massive 3,000 foot limestone, where non-homogeneity is a good thing because over a large area with a variable depositional setting (look at the Bahamas or Great Barrier Reef in Google Earth) there are going to be sweet spots, reservoir quality rocks. Reefs are the highest quality limestone reservoirs due to matrix porosity, the container/envelope for the hydrocarbons. Reefs are expected to be found in a limestone system of that magnitude. InterOil also cored 1,000 feet of porous sandstone. The sandstone is another reservoir rock target which was deposited during similar geologic time as the Toro sandstone, the main reservoir in the PNG highlands. The sandstone InterOil cored is stratigraphically lower than the limestone. They have not drilled deep enough to test the potential of the sandstone reservoir yet because they have been so successful in the shallower limestone, 3) under an impermeable shale which forms the trapping mechanism, and 4) buried at the right depth of about 4,000 to 6,000 feet, creating formation pressure.
The essential elements of a petroleum system include the following:
• Source rock
• Reservoir rock
• Seal rock
• Overburden rock
Petroleum systems have two processes:
• Trap formation
• Generation-migration-accumulation of hydrocarbons
These essential elements and processes must be correctly placed in time and space so that organic matter included in a source rock can be converted into a petroleum accumulation. A petroleum system exists wherever all these essential elements and processes are known to occur or are thought to have a reasonable chance or probability to occur. Petroleum Systems by Leslie B. Magoon and Edward A. Beaumont.
There are two general types of porosity in a reservoir, fracture porosity and matrix porosity. Imagine a solid glass block that has been shattered by a hammer, as an example of fracture porosity. Gas can flow freely through the fractures but there is still not much space for hydrocarbons. Instead of a shattered glass block, you would rather find a jar of glass marbles. The space between the grains (marbles) is matrix porosity. Gas flows well through the rock, is permeable, and there is pore space in the container for hydrocarbons. In the 1950s, no reefs were discovered onshore and many of the show wells encountered fractures. Even InterOil indicated the fractured limestone was difficult to work with after drilling Elk-1. Fractured limestones are prolific reservoirs in many regions, but the most prolific limestone fields have more matrix porosity. InterOil's discovery of the Antelope Reef changed the industry's view on the Eastern Papuan Basin. That might be why Oil Search has now leased the acreage surrounding InterOil's Elk/Antelope play.
InterOil's Chief Explorationist is David Holland. David is the undisputed foremost authority on the hydrocarbon geology of Papua New Guinea having spent almost his entire career in the country. InterOil was the first to use aero-magnetic and gravity data in the Gulf Province. The data was used to identify 40 anticlines with anomalous residual magnetic and gravity readings. The Elk and Antelope anomalies rose to the top of the prospect list because they were deemed to be in the right structural position relative to a good show well. InterOil shot seismic data over the area and identified the Elk fault block which led to the drilling of the Elk #1 discovery well. It took a while to get the science right and InterOil did drill a number of interesting and educational, but sub-economic, obligation wells required to maintain its licenses on prospects identified with little or no seismic data. As InterOil improved its seismic acquisition parameters in its phase 2 shoot over the Elk Field, the results indicated a massive reefal structure south of the Elk-4 well, which was being drilled while the seismic data was being acquired. That data led to the drilling of the Antelope-1 and Antelope-2 wells. Since then, InterOil has shot a phase 3 seismic program with a more concentrated spacing directly over the Antelope reef. All the seismic data is used in combination with the well data to derive a recoverable resource estimate. InterOil has now used the same exploration technique to make another, potentially even larger discovery at Triceratops. There are more prospects maturing to the drillable stage with several phases of seismic data confirming structural closure and demonstrating reflection character indicative of reefal stratigraphy.
Any short thesis would not be complete if it did not try to make the case that the reservoir at Antelope is questionable because InterOil has not conducted an extended, or long-term, flow test. InterOil conducted over 1,100 hours of flow tests on the Elk and Antelope wells. InterOil went beyond industry standard flow tests by installing production tubing in the wells and opening them up to flow at high rates. The rates and pressures are used to calculate reservoir parameters. After flowing at high rates and then being shut in, the Antelope wells returned to reservoir pressure instantaneously, indicative of the high porosity and permeable reservoir and providing reservoir engineers sufficient data for a thorough reservoir analysis. When this short thesis was first promulgated several years ago, InterOil produced the results of all its flow tests in the Antelope-1 and-2 wells in a presentation to the IPAA conference in New York on April 14, 2010.
InterOil applied for an extended test at the Antelope-1 well. PNG's Department of Petroleum and Energy rejected the test indicating that would waste too much of the State's gas. The objective in a long-term flow test is to produce enough gas to drop the pressure in the reservoir by a measurable amount so a material balance calculation can be completed. The amount of gas that would have to be produced to drop the reservoir pressure in the 8+ tcf Antelope field would be enormous and likely take years. And once again, the risked analysis of the reservoir volume estimates takes in to account all the knowns and unknowns.
Lastly, the reason most of the production comes from the PNG highlands is that the highlands are a more temperate climate with grass lands and more dense population. Oil and gas seeps were observed at the surface which ultimately attracted the interest of the oil and gas industry. Once the Kutubu field was discovered there was enough resource to justify a pipeline. Once the pipeline was built all the exploration in the country occurred within close proximity to the pipeline as it was the only means of monetizing a discovery. Without finding any other oil fields the size of Kutubu, the majors lost interest and moved along. Oil Search bought Chevron's assets in PNG.
PNG Political Update and Near-Term Catalysts
Now that the PNG political risk has abated, InterOil is rapidly moving towards its long-awaited monetization. PNG's recent election resulted in a decisive victory for Prime Minster Peter O'Neill, ending months of political instability. Prime Minister O'Neill is a strong supporter of InterOil and is committed to expediting the Project's final approvals. PNG's Cabinet is called the National Executive Council (NEC) and meets this week; Monday, Tuesday and Wednesday. PNG's NEC is the entity that will ultimately approve InterOil's Gulf Project. InterOil's Gulf Project is on the NEC's agenda for discussion this week. Given the dismal state of PNG's national budget deficit, the government is highly motivated to get InterOil's project approved. Once InterOil receives project approval, all focus will turn to the selection and approval of the sell-down partner. The earlier InterOil receives the requisite approvals, the earlier cash flows will commence to PNG's Treasury.
There are 2 likely outcomes over the next few weeks.
Outcome 1 is that Shell decides to preempt the sell-down process and makes an offer for 100% of InterOil. Given the size of Elk/Antelope and Triceratops and the additional 40 identified exploration leads and prospects, InterOil will not sell itself cheaply. Using GLJ's Elk/Antelope estimate of 9.4 Tcfe (this number includes the condensate liquids) and assuming Triceratops is at least of equal size = approximately 18 Tcfe. InterOil owns 58.6% of the resources. 18 Tcfe X .586 = 10.5 Tcfe. Assume that InterOil's resource will sell at least at the average of recent comparable transactions of $2/mcf. This is extremely conservative given that InterOil's production cost is much lower than other projects in the comparable set and this assumes ZERO value being given to the other 40 prospects, the refinery and downstream assets. $2/mcf X 10.5 Tcfe = $21 billion. InterOil has just under 50 million shares (fully-diluted). $21 billion/50M shares = $420/share. Regardless of the degree of further risking applied to this analysis, the result is a final transaction price equal to a multiple of the current share price.
Outcome 2 is InterOil completes a partial sell-down of E/A to Exxon (XOM), Shell or Japex/Kogas/Mitsui at $2-$3/mcf. InterOil will likely receive several hundred million dollars of cash upfront and will use the cash to markedly expand its drilling program, likely focusing on prospects Whale, Mako and Tuna next. The discovery of additional reefal formations will continue to propel InterOil's value higher.
Either outcome is a huge win for InterOil shareholders. The upcoming weeks are an exciting time to be an InterOil shareholder.