The rumor, presently, is that the FED will allow WTI export. So far it only pertains to the light WTI or field condensate. The FED does not have an API threshold to qualify condensate. The deference between Field Condensate and Plant Condensate is the process used to remove the light particles which permit the transport by pipeline. Obviously the refinery process does that, this is where the Field versus Plant terminology comes in. There is an export market for condensate Field or Plant; it is just that the FED is behind the ball, as usual.
It is a given that WTI is permitted to be exported to Canada. The Canadians export their light crude at world price and import US WTI at discount price to be used in their refineries, for local needs. Now another export market for WTI is about to open up to US producer of WTI, Mexico. Mexico cannot produce enough crude to feed their refineries. PEMEX has not allowed import of crude, but permitted the import of refined products. The new Mexican petroleum law, passed recently, will facilitate the import of US WTI. This is OK as part of the NAFTA. The Eagle Fort WTI crude will probably be the beneficiary.
Any export will be the controlling factor of the level of WTI discount. WTI price may not crash as much.
I am afraid you do not understand what a US Royal Trust (USRT) is. At best it is a US Bond that yields a 9% or 10%. But over time you lose the equivalence of the distribution of this USRT. At some point the index price of the oil, gas or NGL can no longer keep up with the lost value caused by the distribution. If you are long with a USRT you have to subtract from the unit purchase the distribution. What is left is your profit. If you keep it until the end, the unit price will be zero, what are left are the distributions.
I trade all USRT and I play the Xdate bump and rarely take the distribution. The attraction by most traders is the level of the quarter distribution. WHZ price varies up to 2 dollars between the day after Xdate and the day before Xdate. I make my money by timing my buys and sell. So far I am doing OK, but it takes research and spreadsheets to keep up with the daily price fluctuation.
Yes, steam has a different use than fracking water or gel. As for the earthquake, regardless it is not compatible with production casings or stems which may be thousands of feet deep. Since earthquake is the release of geological pressure between 2 formations, fracking may release this pressure. Can fracking control this release is an open question. I do not have the answer.
I do not believe that Fracking is going on in California. The difference with Fracking is that you must keep on drilling to produce crude. In the standard reservoir you drill x number of wells and you produce from them for years. Not the case in shale play. One the fracking is complete you can produce what is freed from the rocks. But for a limited period of time, 5 years is a good producing well, but will have lost 80% of the IP or more. Than it is a question of the cost of maintaining the well so it can produce. That cost may be more than the production profit.
On paper reinvesting the distribution make sense. In reality USRT as a depleting asset the unit price will not match the distribution, if you keep your units for the expected life of the USRT. Personally I do not, I don't even take the distribution. I sale a few days before the Xdate and track the dip of the unit price passed the Xdate. When the percent drop match the average of the USRT, I buy back. Does not work every time but works for me. I keep track of all news and MB, tracking the unit price between quarter is a good indicator. USRT will always go to zero, you have to expect 15% or so drop every so often, the SA article was one way that traders reacted. Other drops are correlated with reserve percent left to be produced and sold. The index WTI price has to be taken in calculating the value left to be produced.
Any and all IRA or 401K distribution will be reported by the broker. You will receive a 1099R. You will have to report it on your 1040, no choice. Depending on your taxable rate you may or may not pay taxes on this distribution. The twist is with MLPs, the Earning Before Interest Taxes Decompression Amortization or EBITDA may have to be declared. Above $1000 you should see an accountant.
I assume you are thinking of the Paso Robles oil field. This oil field uses steam to allow this very thick oil to be pumped to the surface. Steam is used once the drilling is completed, and dilutes the crude too thick, kind of like bitumen, to flow. This is still a standard oil reservoir; it is like a large pocket of crude.
So far steam has not been used as a fracking medium. On the other hand, Gelfrac is liquefied NG with the propan added and is used as drilling fluids, in the same manner as drilling mud. The liquid NG part of the drilling gel comes back to the surface as gas mixed with what the fracked rock healed. The advantage is that no water is used; this is important in areas where the availability of water volume is limited. Excelyte is another product, water based, that can be used. Excelyte is added to the water and allows this water to be recycled as drilling fluids. Excelyte eats up bacteria, such as H2S and others and eliminate the none ecological discharge without further treatment, such as chlorine for example. Naturally Gelfrac is liquefied NG therefore more expensive. Excelyte is cheap in comparison.
On 12 March 2012 the total declared production was 11,790,000 BOE, So far the WHZ has produced 4,205,526 BOE, so 7,584,474 BOE is left to be produced. I missed quoted the production left to be produced, 55.48% is left to be produced. WHZ has not passed the 50%. I use 6 BOE = Mcf to convert NG to barrel of crude. This BOE is not straight forward. The 6 Mcf of NG represent the BTU equivalence with crude oil. This is used to price the NG in Europe. The Russian and Qatari NG is priced on this value. So the European NG price follows the Brent index price.
We, in the US, use the Henry Hub index price which has nothing to do with BTU equivalence. The Henry Hub price is based on demand and availability. If you were to cost the BOE left to be produced, the NG contain will be different depending on what Mbtu price is used. None the less WHZ has a few good quarters left. I am watching WHX to see and learn what will be the end of WHZ.
So far WHZ is my best investment. I am in for the 3er time this quarter. With the production just declared WHZ has produced 55% of the 11,790K BOE. Still have few quarters with descent distribution. Finding other URST as good as WHZ is not easy. The returns versus the unit price is a big plus with WHZ. Hope you are doing a killing!!!! LOL
Investing in an USRT is straight forward. The investment represent the oil, gas or NGL. The unit represent only this commodity. The operator sales the commodity. The operator calculate the distribution after deducting all expenses and maintenance fees occurring during the quarter. The distribution represent the net profit for the quarter less the taxes. The investor is responsible for the taxes. IRA or 401K are tax free investment, until the financial instrument owner take distribution. The IRA or 401K distribution is taxed as ordinary income. Naturally if your taxable rate is 40%, meaning above capital gain, 15%, investing in USRT or MLP are not the preferred choice. You are better off taking the capital gain. I am retired so no salaries, just IRA distribution plus retirement.
The use of API grades must be taken with the refinery equipment. Many refineries were set up to use Brent or API 40/43. Today Brent does not get inland any longer. Brent produces more diesel than gasoline as a percent of the crude processed. For this reason WTI was discounted from the Brent and the LLS. The Canadian Railbit contains 20% condensate and Dilbit 30% condensate. This is required so the crude can flow in pipelines or be loaded/offloaded in rail cars. This Canadian crude does not fetch the same percent of gasoline and diesel. To mitigate these heavy crudes some refineries have invested in Hydrocracker. That has far as my process knowledge goes. All I know is that it cost and it has to be amortize, therefore pressure on the distribution.
The shutdown will pressure the Q3 distribution, how much, varies with the crude throughput and the index prices. As long as the GOM has 22 days of storage available, the discount at Cushing will be minimal. I would not expect a favorable crack spread for the inland refineries. It will come back in 2015. All point out that the crude going to GOM will double in volume by 2016, meaning the back up to Cushing will take place again. This will not happen at once, so some crack volatility can be expected.
CVRR refineries location means they use WTI or WTS. Brent is no longer available inland. Several pipeline that used to deliver Brent have been reversed. Looking at CVRR margin, it is spot on the average Crack for the year, the 3-2-1 crack. Looking at all inland refineries, I use the same crack to verify their margins. There are 9 recognized US crude grades plus the Brent. All have different index prices. The west coast use the Alaska North Slop (ANS) which compete with Brent, the only WTI on the West coast arrives by RR. There are no pipeline going east from the Bakken, the WTI to the East Coast get there by Jones tankers. This means that Brent is very competitive on the East Coast. Jones tanker are tankers that only travel from US port to US port. US law does not permit foreign flag ship to move anything from a US port to another US port. Jones tanker cost double versus foreign flag tanker. This cover also the ANS to the west coast.
I calculate the 3-2-1 crack spread, the crack used by the majority of O&G pros. Chevron has it own, I believe 5-3-2. This 2-1-1 is the Brent crack which is not used by many US pros.
I take the price of 3 barresl of crude at the WTI index price and compare with the price of 2 barrels of gasoline and 1 barrel of diesel. I use the GOM EIA published prices. Brent crude imports are down on the GOM. The East and West Coast see Brent crude imports still in sizable volume.
The distribution is $.96 per unit is a respectable distribution. The days of super crack spread are over for the time being. Will the crack comeback, yes, in 2015. My average crack since May 1 is $15.43 and $13.97 since January 1, 2014. CVRR adjusted margin of $13.96 is on the money with my average for 2014.
The fire will cause a shutdown of the refinery for 3 to 4 weeks. CVRR will cumulate the scheduled maintenance so as to not have any more scheduled maintenance shutdown. Q3 distribution will be impacted. This situation goes with the territory of trading with refineries.
Trading in the O&G sector means that $.96 is above average, I forecast an up surge within the next 7 days. The only potential game changer is WTI export; I do not see this happening until 2017. Field condensate export will mean more storage on the GOM coast. Any back up to Cushing OK will be limited unless we see an up surge of new WTI production. This support my 2015 crack spread comment.
From an accounting point of view, the Q2 end 30 days prior the Xdate +3 days. It does takes time to close the Q2 books, calculate the distribution, pay the bank. The board of directors has to approve etc..
If there is a loss of earning it should be minimal. Any production lost should have been makeup by the storage at the refinery. My guess, this fire may, I mean may be reflected in the Q3 distribution.