Valuation work from IV P3CMS

[jft310]

My take on the IOC Deal

Here’s what I think I know, after two press releases,the conference  call and prior to reading the 80 page deal document.

First, at the highest level, big picture, the fact that they went with Total makes perfect sense if they are pretty sure they have a lot of gas. If they went with XOM, were they going to get 30% of the retail action?  Obviously not (Citi estimated 11% for a 4th train at PNGLNG ) and it is understandable for XOM not to give them that. But if they only have a little gas, say enough for two trains or even three, sure, go with XOM and get it monetized and to market quickly but at a lower profit level.

But retail is where the big money is, even though this is not being discussed in the release or the conference call. Spot prices pushing $19 in Asia, analysts expecting demand to outstrip supply  for the foreseeable future,  long term contracts are apparently in the $13-$15 range now (though I don’t have first hand knowledge of that).

GLJ’s best (50-50 case) for E/A resources only,  is 9.07 TCF, confirmed in  today’s 1st release. If you assume $5 in all in costs post the plant being built, $8 – $10 profit per mcfe profit is possible, $72-$90B in profits could be generated.  30% ownership says $21.6 to $27B in profits would accrue to IOC over the life of the 9TCF. PV10 that cash flow. This is the key to the deal, not the short term resource payments.

Rinse and repeat with  gas found in Triceratops, Wahoo, Raptor, BobCat, all labeled as multi-TCF prospects. And also, apparently, another structure mentioned today (Elephant-1?) that is within PRL15. This well is going to be drilled 4q14 to 1q15 per the CC, so my take is it is not one of the above prospects. It was described by Hession to be as big as E/A, maybe bigger. Total is funding it and paying for gas found in it, but IOC will retain the 30% interest of retail as this gas has to be assumed to go thru the same JV / Gulf LNG plant.

Meantime, back to the short term details.

Some payments to IOC from Total are fixed, some are variable.

The most significant fixed payment will be for $613 million upon transaction completion, expected 1q2014. This allows IOC to pay the $250MM loan back and keep on drilling (with leftover $ toward the plant). There are also two more fixed payments, one for $100MM and one for $112, but they come in 2016 and later.

There are two significant variable payments  to come with 1) the finalization of the three appraisal wells, in 2015, and the subsequent recertification of E/A and 2) a second recertification, whose timing (date) is a wildcard, that will be determined by IOC. IOC has done this for good reasons too lengthy to mention here(but statedon cc), but it allows for further PRL15 drilling and higher amounts of gas to be found, hence higher payments to IOC, probably in 2016.

The formula (from today’s 2nd PR) for determining what IOC will get from Total for the two events above is as follows –

Recoverable hydrocarbon equivalent

Unit Price Pre-Gov't

Back-in

Unit Price Post Gov't

Back-in

>3.5 Tcfe and

US$0.60/mcfe

US$0.77/mcfe

Paid at FID

> 5.4 Tcfe and

US$0.80/mcfe

US$1.03/mcfe

Paid at Certification

> 6.5 Tcfe

US$1.00/mcfe

US$1.29/mcfe

Paid at Certification

The dollar amount to IOC that the above formula computes to is therefore based on the amount of gas certified. Examples can be seen below (from today’s 2nd PR)  –

Resource Level

Indicative Payment

Pricing Table US$0.77/mcfe Level

5.4 Tcfe

US$1.5 Billion

Pricing Table US$1.03/mcfe Level

6.5 Tcfe

US$2.1 Billion

GLJ Certified Best Case

9.9 Tcfe

US$4.1 Billion

GLJ Certified High Case

11.8 Tcfe

US$5.3 Billion

Note the GLJ certified best case 9.9 TCFE figure above that would net IOC $4.1B

In the first PR today, IOC displayed the following table.  GLJ, IOC’s 3rd party appraiser, had this to say about the volumes in E/A on 12/31/12

As at 31 December 2012

Case

Elk / Antelope contingent(1)(2)

Low

Best

High

Initial recoverable sales gas (Tcf)

6.83

9.07

10.85

Initial recoverable condensate (MMbbls)

111.5

135.4

156.3

Initial recoverable (MMboe)

1,250.1

1,646.3

1,965.4

I am assuming that the 9.07 TCG of gas plus the 135.4 MMBBLs of condensate foot to (equal) the 9.9 tcfE worth $4.1B in the prior table

So, if IOC has what the 3rd party GLJ thinks it has, it will receive $4.1B in 2015. Plus it will also have received $613MM in 1q 2014. Compare that to its present market cap. Then factor in the key cash flow profits stemming from the 30% ownership in the LNG plant. Factor in Triceratops, Elephant-1 and the 2 or 3 other multi-TCF prospects being drilled next year with the 4 rigs now under contract and put your risk factors on those wells/fields. Sounds like a great future to me.

[ltinvest]

Completely agree. IOC at $55.50....insane

[SamAdams]

Thanks JFT

[ebster123]

Correct, it is insane, but that is where it is and this is criminal. In addition, all longs here for a significant period of time have heard about the big shorts saying they have backing and will pile cash in to drill the pps down on news. To not make the presentation today seamless and exact was a bush move. Kinda reminiscent of the old IOC.

[jft310]

Another IV poster says this badlybadly

My take on what the 3 appraisal wells will do in E/A

  Since Total's total payment to IOC will depend on the resource size of E/A after these 3 new appraisal wells in 2014/2015, here is what might be the outcome imo.  The existing contingent resource from GLJ is shown below.  I will focus on the gas numbers only, the condensate will be proportional to the gas.

As at 31 December 2012

Case

Elk / Antelope contingent(1)(2)

Low

Best

High

Initial recoverable sales gas (Tcf)

6.83

9.07

10.85

Initial recoverable condensate (MMbbls)

111.5

135.4

156.3

Initial recoverable (MMboe)

1,250.1

1,646.3

1,965.4

I will use round numbers of 7TCF, 9TCF and 11TCF for the Low , Best , High.  The payout will be based on the Best case number using an average of the new resource size (IOC chooses their company to do this, Total chooses theirs).

The resource size is a combination of the volume of the structure (how big the reef is, using length - width - height) and how much porosity it has (the hydrocarbons are contained in the pore space, i.e. the void that is not rock). The wireline logs will determine the gas / water vertical contact line so the hydrocarbon volume can be calculated.

In scenario #1, lets assume that the 3 well results are in-line with existing drilled wells, the structure height matches seismic and the porosity is within the currently used average values. Since none of the new wells prove that the areal extent of the E/A field  is any bigger and the porosity matches earlier models, the only change should be a tightening of the Low and High towards the Best value.  So something like 8T,9T,10T would be the new result. This would not result in any higher payment since the Best case value is unchanged.

In scenario #2, lets assume that one or more wells prove that the size of the field is larger or the porosity found in the well is better, this would shift all the values to a greater number.  Perhaps something like 9T,11T, 13T.

Since the final tranche payment will be based on the middle (Best) case average, I would say we have a floor value at this point based on the existing numbers.  If one or more of the new wells causes the Scenario #2 option to occur, then final tranche payment will be substantially higher.

[Getitrt2]

It is my understanding that the existing wells in Antelope are roughly in a line along the Antelope formation. As a matter of fact, I seem to recall that Antelope 3 was drilled between 1 and 2 at least partly to confirm continuity of the formation. Given that, I believe additional appraisal wells would be stepping out perpendicular to that line, and at least in one location where the formation appears to be deeper, and therefore may very well allow for certification of a larger formation and significantly greater resources. Perhaps that is why Hession seemed to feel strongly that there is likely to be upside to the resource estimates and certifications. I would say he cannot predict or reasonably try to quantify that now, but it would be HUGE to end up not far down the road with a much bigger variable resource payment than currently anticipated.

I am sure that Petrengr1 has more detailed knowledge of all this and could better evaluate the thesis, and would be very interested in his comments, whether I have something or am misinformed. Also, I assume the payment would be based on the "Best Case" estimate of new certifications, although probably within a narrower range after additional wells; is that right?

[strategyguy536]

Getit, I agree completely Some appraisal wells are more accurately called "delineation wells," for they try to delineate the boundaries, not the sweet spots, of the field.

[Putncalls]

The shorts will eventually loose control. Think about about it. The Japanese could buy the whole thing.

[jft310]

Or Exxon or a Total or.....

[johnwgrant]

The shorts will eventually loose control. Think about about it. The Japanese could buy the whole thing.

Good point.   What is the risk for Japan Inc. to buy natural gas at $1 or so per mcf knowing that they are currently paying $15 to $20 per mcf delivered in Japan ?

(and by risk, I am alluding to the risk of losing their investment.).     So, their downside is that they have a 'marginal' field which will need to be grouped with other fields to justify an LNG plant (highly unlikely, but, a small possibility).   The Japanese upside is that they save 50% on their utility bills for 20+ years (starting in 2020 or so).

I think the risk/reward is skewed very much towards REWARD !!!