Kurt, you need to read my comment. I am saying that WHZ will not have 33 distributions. It all depend on the volume produced. Maybe the production will dwindle over time and the distributions will suffer. That is not what I am looking for.
Liza you with it, and get it. The speed at which Bakken and Eagle Ford increased their production has taken the market by surprise. My belief is that the flood of crude going to the GOM is 6 month or even 1 year ahead of schedule.
GOM refineries are producing too much gasoline and not enough diesel. This has to be with the API crude degree. Lighter the crude means more gasoline and not enough diesel, diesel that Latin America wants. My guess is that too much gasoline will force the GOM refineries to dump excess gasoline in the inland markets and even use Jones act tankers to feed the east coast. To give you an idea of the flood going to GOM: total GOM refineries capacity is 3.7MMb/d, today we are approaching 4MMb/d flood to the GOM. It will get worst by the end of 2014? This does not go well with ALDW which is close to the GOM. I have seen ALDW market area, it is mostly rural, meaning diesel rather than gasoline. Gasoline is at $2.52 per USG, will be $2.00 by this time in 2014 or earlier.
The Big Spring modifications were stated in the last conference call. The Brent CME has a world price, base on world demand. The WTI, WTS and ANS are the US produced crude widely used, since it cannot be exported. The west and east coast are more and more using ANS , west coast and Brent CME east cost. Bakken crude is competitive with R&R transport.
The WTS price discount is small because the diesel export market is where are the profit, today. The crack spread is coming back, because the crude flooding the GOM exceed the demand capacity of the GOM refineries. Inland refineries should see a crack again. The WTI price will drop due to this flood, the Brent will find other customer else where. The word is that the WTI will go for $80 in early 2015. NG will not help, especially with the trucking and power plants.
This is an interesting argument. It is understood that crude oil price will fluctuate. It is also understood that supply and demand can be affected by local conditions. I make reference to the Cushing OK hold up, it has created a discount and altered the index price of crude oil.
The discount price intends to attract demand so the operator can earn enough to pay his management fees. My contention is that a hedge price is the same thing with a different name. Agreeing to a discount price for a set period of time insures an earning therefore distribution. It is the tool to control the fluctuation of, in this case WHZ price. The cost of management requires some earning stability. Passing a contract for a set period of time with a specific price is defined as: Hedge or discount? Oil companies never pay a project with their cash. They borrow money with their good name as guarantor. The loan interest is the LIBOR rate plus a negotiated percentage.
Should WHZ contract the sale of the production based on the index price minus a negotiated dollar value. This price is fix regardless of the index price. BPT uses the GDP movement to assess the percent change of the BPT distribution amount. Is this a hedge or a discount?
As owner of WHZ I do not want to see the fluctuation associated with ALDW for example. I have owned ALDW but knowing that there is a volatility associated with ALDW, which is fair game. WHZ produces within a small volume differential every quarter; the index price is the principal price changer.
Lisa, I always took your postings as pertinent and interesting. The comment regarding the WTI/Brent CME applies only to the GOM. The east coast refineries are using Brent there the competition is the Bakken R&R transport. For the cheap GOM WTI to get to the east cost the Jones Act tankers are the only real possibility. But the cost of Jones act tankers transport US WTI makes Brent competitive.
For the west coast the ANS is again in competition with Brent CME. ANS can on be transported by Jones act tankers. Bakken rail transport is making progress, but only in Washington and Oregon states. California is putting road block to the construction of R&R unloading station. The construction permits take more time that in the other 2 states. So WTI/Brent CME is still pertinent, but not every where.
EIA has the definition of the crack, difficult not to accept their definition. When it comes to ALDW specific crack, it is different. ALDW does not use LLS but WTS and WTI. WTS produces more diesel than WTI, a question of API degree. Today with the crude access to GOM, and the export market of diesel, WTS is in more demand. This is why ALDW is adding a hydrocracker to the Big Spring refinery. ALDW will be able to use WTI and produce more diesel. ALDW market is rural, I would think that diesel is in more demand.
Let me see now. Silver bay is a protected port with lots of room for storing IO. As a mater fact, I can see a large area with IO traces on the ground and even a sizable IO stack adjacent to the pier. Also a train is shown, looks like it was just unloaded. There is no barge tied to the pier. I guess, unless the barges are in dry dock, they are in water, and the water will freeze. In March, when the lock open again, the freezing season is over, although some ice is still around the lock area depending on the year. You most likely live in another world.
Question? Has any one double check the K8 - Q3 dated 4 October 2013. The listed distribution is $0.68. But the Net cash proceeds available for distribution divided by the outstanding units shows $0.98. Is there a correction, or am I wrong?
Call it what you want but the average price of WTI since the IPO is $95.54 and the average price WHZ has received from sales is $70.77. What an hedge does is for a set period of time, guaranty a price what ever the market price is. In so doing It guaranty a fix income and a fix distribution. The volume produced is the only variable.
It is possible that WHZ price is headed. Therefore the quarter earning should be the same, the volume produced is what to look for, it is what distribution is based on.
With the locks closed to traffic, barges cannot steam through the locks. Unless the barges can find work in the lower great lakes during the cold weather, it would make sense to tie them to the Silver Bay piers. During the locks shut down, IO production continues, the IO has to be loaded on trains to get to Silver Bay. Make sense to store the IO until barges are available. It would make even more sense to have barges loaded, steam whenever possible, to the entrance of the lock, and pass through as soon as the lock is open. It would be a mistake not to have buffer storage at Silver Bay, just in case the RR has a traffic problem. Should it derail, for example, 2 weeks buffer minimum would make sense.
Time is money; the icing makes barge traffic difficult or even dangerous. If the barges have to be idle, better use them as storage ready to steam, whenever possible.
So far WHZ has produced 2,999, 275 barrels of crude out of the trust total volume of 11,790,000 barrels. The average quarterly production has been 635,701 barrels. So assuming the same production average, the trust will attain the 11,790,000 barrel in 6.17 quarters or 3 years 6 month. Or May 9th 2017.
So much for the 33 quarters left. If I am wrong let me know?
Do not expect any shipping from the reopen mines until the winter locks shutdown for maintenance is done. This shut down happen in late February March. Once the mine reopen the IO will be stored for shipment at Silver bay. What you want to know is how many barges are tied at Silver Bay during the shutdown. So as soon as the lock open the barges will steam to their destination.
Buying refineries is not hot these days. ALDW is a small rural market, not attractive. The US gasoline market will not expend soon, the diesel is for export. Inland refineries depend on crack spread for profits. I would not be surprise if the majors refineries dump their excess gasoline production in the mid-west markets. This will not be that good for the inland refiners.
These MBs are only for taking the temperature. You have to do your own research and see where your conclusion fit. ALDW is on my side line until the turnaround. Than will see where the crack is.
It is important to understand how a trust operate. The trustee manage the moneys they are given, according to the by laws of the trust. Trustees have nothing to do with management of the operation. In commodities trust, the trust own the commodity, oil, NG, IR etc. Trust do not own or manage the installation use to produce the commodity. MLP are totally different, like night and day.
The declining value of a trust, such as WHZ, is offset by the price of crude or /and NG. You can figure this out by keeping track of the production minus the anticipated volume to be produced.
The production start to undermine the oil of NG price when the volume left to be produced can no longer keep up with the crude or oil price increase. This normally happen on the last 1/3 of the trust life.
The oil boom that we presently see will bring the WTI down to the $70s or $80s. US production cannot be exported, and the US refineries will not be able to handle the WTI and dilbet or railbit, so price will go down. Than ALDW and CVRR or NTI will be the ones to deal with again. Deja vue all over again!
The facts are that the Trustees are silent partners. There are exceptions such as MSB, the trust has an inspector on staff that verifies the Iron Ore shipments out of the export port. This is because the trust gets a percentage of the Iron Ore production only. On several occasions the amount of production and the moneys, as described, did not match.
More times than not, trustees are a banker manager and a secretary that split their times between several trusts. The owner operator is the one making all the monetary decisions, as Obama would say “Period”. LOL You understand, I may be wrong?? LOL