HRZ Shale Decision Tree, page-51

1/ ''I wasn't talking about buying up leases nobody wants.'' eh?
Sorry, I meant the Yukon Gold leases. One of the posters equated PL capacity reservation register to buying up leases - should have made it clearer.

2/ Do COP or others determine who can or cannot use TAPS, when less than 50% is utilized?

TAPS ownership last time I looked - keep in mind the BP / CoP asset swap deal may change the percentages. Haven't looked into the smaller details of that deal yet.

• BP ~ 50%
• ConocoPhillips ~ 30%
• ExxonMobil ~ 20%
• Others ~ the rest

Agree that they will still seek a return, but if you were them, and you had a possible few billion barrels to get to Valdez and you needed surety around export, would you let someone else have first, second or third usage rights? If the capacity allowed maybe, but that's not until their new projects come off plateau - which could be a while.

3/ Suggest you contact DOG who are responsible for permits with environmental control remit. I am pretty certain they thought about this and got it covered.

They had something covered indeed. The production test post stimulation that is. Given they expected a minimum 30% injected water to cycle through, and given choke size, that's probably 3k to 8k bwpd over a test of a few weeks. Not much water, and relatively easily handled, hence the ability to get the permits required. Much like Buru up North in WA. Production is a whole different ball game.

4/ Why is this a seasonal issue? once oil flows it flows 365 days a year. The well base is 130c, yes there will be cooling as the oil comes up the pipe, it will be no where near freezing. TAPS is also heated.

To keep plateau on an unconventional project you need to drill a well every two days or so, round the clock, for years on end. Completions and fracking can wait but you can't afford to fall off that schedule, especially if you're hoping to sign a transportation agreement with a pipeline. They will charge you whether you put product through or not. Multiple rigs, roads, well-pads, ponds, gathering lines - none of those things are there now. And a lot of those things need to be bespoke to the Arctic conditions, that is, new-build and expensive.

As for TAPS being heated... It isn't. Very common mistake though. It is heavily insulated, but those "heaters" you see on the side of some sections of the pipeline are ammonia/CO2 exchange pipes that are there to maintain ground temperatures and avoid thaw/freeze around the supports. They are not there to heat the pipeline and allow product to flow - hence my earlier comment that oil is being circulated North to South at the moment to literally keep it flowing until the volume in the line-pack reaches that of a laden tanker (i.e. ~ 2 mmbbl)

5/ In addition IW1 samples show the shale to hold high end API, highly viscous and very much in demand. A ''Half brain'', would understand its value.

There is no need to be nasty. All oil-bearing shale crude is, by its very nature, high-end API. Which is not the same as oil shale, which is mined. The stuff 88E is targeting seems to be liquids-rich gas - with the gas requiring flaring as explained before. I cannot confirm it that is what these Icewine wells are actually targeting.
A second TAPS will only carry gas, not oil, to ensure the massive North Slope field gets developed. But talks with government about that pipeline (i.e. the govt should invest in it instead of the companies) have been taking place for decades. In fact, a former boss was right at the forefront of those talks for some time. I hope they come to fruition.

Also, you are correct that high-end API is cheaper to distill - unfortunately the non-88E oil everyone else is targeting nearby, and wants to put into TAPS, is the usual AK thick and heavy crude. One more hurdle in the pipeline volume aggregation issue - i.e. will the owners allow different spec oil through? Don't know. Doubtful. If nothing else it will mean a complete re-working of transportation and aggregation arrangements that will require more time, money and attention from the owners that they may not see as fruitful in the near to mid term.
Also, just for the record, why do you think the US L48 has to change federal laws to allow export of a lot of that similar high-end crude? And yet they still import more and more? Shouldn't the US have gone into import-replacement mode rather than export-mode? Well, as the refiners spent billions and decades re-fitting their refineries to take the heavy stuff from Canada, Alaska, SA and Central/South America. So that light crude, if it does get allowed to go into the pipeline to Valdez, will also need to find refineries further afield, like the "teapots" of Eastern China; and that will eat into the realised price per barrel too.

So, apologies for the long diatribe, but as more and more companies prove up their conventional portfolios in AK, these unconventional leases are falling further and further down the rankings. Shale barely broke even in the most infrastructure-rich parts of the Lower 48 at $50, it will not do so at $80 in AK. And that's for a proven resource, not one in its infancy, in one of the most unforgiving environments on Earth.