Perhaps there's something here that eludes me.
"Total motor gasoline inventories increased by 1.7 million barrels last week, but are in the middle of the average range. Both finished gasoline inventories and blending components inventories increased last week. Distillate fuel inventories increased by 1.4 million barrels last week but are in the middle of the average range for this time of year. Propane/propylene inventories rose 1.9 million barrels last week and are well above the upper limit of the average range. Total commercial petroleum inventories increased by 2.9 million barrels last week."
Now, to me, those statements taken together suggest that refiners produced more finished fuels than they could sell, which in turn suggests that supply outstripped demand for those products.
Inasmuch as crude oil id the feedstock from which these are produced, one would logically suppose that this lack of demand would reverberate down the supply chain, but evidently that isn't the case.
I don't use their charts. Under the "Tables" tab, they have links to Excel workbooks that have numbers to the nearest 1MBbl. In the case of Cushing, for example, the last four weeks in that format are 57,164MBbl, 57,113MBbl, 57,439MBbl, and 57,695MBbl, respectively (see Table 4).
In my own database, I have this displayed as MMBbl to the nearest 0.00 digits, so last week and this show as 57.44MMBbl and 57.70MMBbl, thus my hasty figure of 260MBbl. With rounding removed, it's actually 256Mbbl.
Using the tabular data, the same week last year was 20,663MBbl.
I assume you've read over the minutiae of today's storage report. One little item that I noted was a build of 260 MBbl in Cushing, which suggests to me that, whatever our other storage / production situation might be, true WTI numbers are still on the bearish side (assuming that Cushing is THE hub for WTI crude).
I'm still mulling it over, but it occurred to me last week that one possible solution might be to curtail imports. I believe we might, for example, dispense entirely with imports from Saudi Arabia, and make up the difference (if we need to make it up at all) with a combination of domestic production and imports from trading partners in the Americas.
I sometimes think you and I could do at least as well sitting on my back porch over a few beers and throwing darts at a numbered matrix.
And, I did see in our local paper this morning that BP-Whiting was restarted as of yesterday. I also stumbled upon a site called Oil Price Information Service that has a very comprehensive listing of refinery maintenance turnarounds, organized by PADD. Well worth reading, and, at least as of today, seems to be very timely. According to them, there are quite a few scheduled maintenance events upcoming in the next few weeks, although I haven't yet waded through it to tot up the offline capacity for the various periods.
I don't even have a guess myself this week, given the wide range, here.
I do, however, keep track of Alaska production (daily figures are available from their taxation department), and noted that last week (this week's EIA report) they were down under 400 MBBl/d for the first time this year. Not sure why.
I suppose that, plus some reduction in the lower 48, plus a massive decrease in imports, might get to the API's number, but I'm skeptical, especially with close to half of BP-Whiting's capacity still offline.
I reckon we'll see come 1030 tomorrow.
Once again, the API's storage guesstimate for the week and the Platt's survey are on opposite sides of the aisle. Te Platt's survey consensus came in with a build estimated at 1.9 MMBbl. The API, on the other hand, is calling for a massive draw of 7.3 MMBbl. I had to look twice at that number to be certain my eyes weren't deceiving me.
The API's track record vis-a-vis correlation with the EIA crude oil storage reports isn't a terribly good one, but this week's guess seems to me simply incredible.
I don't have a dog in this hunt, but merely as an interested observer, I'd think that at some point the fund operator needs to give some thought to getting the PPS back up over a buck, or risk getting busted down to the OTC.
Unless the entire Arabian peninsula suddenly slides off into the sea, I'd think a reverse split is in the near future, no
As of 31 March, the EIA had working U.S. shell capacity at 540.571 MMBbl, and total capacity at 659.206 MMBbl. The same report listed Cushing at 71.409 MMBbl working and 86.301 MMBbl total.
By my reckoning, that puts today's storage report at a bit north of 84% of U.S. working capacity, and slightly more than 69% total. Cushing is hovering at right around 80% / 67%.
I'd note, however, that every capacity report in the last 7 years has shown additions to capacity as compared with the previous report, and I have no reason to expect that the next one will break the pattern. The next issuance is due in November for capacity as of 30 September.
"Anyone see a bull case for oil?"
I don't. In fact, notwithstanding that the API is projecting a 2.3 MMBbl draw this week (to be taken advisedly, as usual), I also heard a rumor that Cushing is expected to show a build of something in excess of 300 MBbl this week. If so, I'd attribute that to the outage at BP-Whiting.
My own background is engineering (now retired); over the course of my career, I was required to be familiar with a number of disciplines, including combustion process engineering.
I doubt whether Hongli could be competitive outside China. As it is, though, natural gas prices there are so high that they can have an advantage. Consider:
The last-announced Chinese contract with Gazprom (Russia) was for $0.360 per m^3. If we consider "pipeline" natural gas to have a HHV range of 0.9 to 1.1 MMBtu/Mcf, this gives us a range of around 0.032 to 0.039 MMBtu/m^3. The price range, therefore, for the Gazprom contract would be $9.2763 to $11.3267 per MMBtu, depending on fuel quality. The contract was most likely negotiated on the basis of 1.0 MMBtu/Mcf, which would put the price at $10.1941 per MMBtu.
Carbon monoxide (CO) comes in at around 0.01961 MMBtu/m^3, while hydrogen (H2) is around 0.012084 MMBtu/m^3. "Syngas" is typically a blend of the two, usually heavily skewed toward CO. Hongli has indicated their ASP for their syngas product to be around $0.10 per m^3, which would give us a range of about $8.28 to $8.36 per MMBtu (assuming a range of 100% CO to 100% H2). On the sole basis of cost per unit HHV, then, the "Syngas" is competitive.
Obviously, considerably more volume "syngas" is required to equal the heating value of natural gas on a volumetric basis, and not all customer equipment would be capable of managing this increased flow without modification. However, some customers will be able to use this as a direct replacement, and high volume consumers may find the price differential attractive, even with the cost of burner modification added to the calculus.
I just saw a piece on Reuters' service that said PEMEX was seeking approval for 100Mbbl / day. Then, of course, it is characterized as a "swap" so presumably, that means 100Mbbl / day would be coming back in.
According to the EIA, we've been exporting over 500Mbbl / day since mid-June (576Mbbl / day on the last two weekly reports). With that in mind, I'm having a tough time seeing where exchanging 100Mbbl a day does a whole lot to improve the price. Naturally, I could be missing something.
I think you're exactly correct.
You'll recall that, in early reporting, a downtime estimate of 10-13 days or so was mentioned. In our local paper today, they're now talking about a month or more. From what I understand, right around half of the BP-Whiting facility is affected. In the grand scheme of overall capacity, even just in PADD II, that doesn't seem a lot, but location is everything, and in the Illinois-Indiana-Michigan-Ohio area we're feeling the pinch (I'm in Ohio).
I don't know whether CETC had any product there, but there were a couple of details in a news account I read this morning that may-I emphasize may-point to a cause.
1) The explosion occurred shortly after firefighters had arrived to deal with a smaller fire at the facility.
2) Amongst the items warehoused there was calcium carbide (CaC2). Calcium carbide is used in acetylene generators; when combined with water, it liberates acetylene gas.
This, of course, leads us to one potential cause-the use of water as a fire suppressant in the original fire, if allowed to encroach into the CaC2 storage area, uncontrolled release of acetylene would be a possible outcome.
I certainly don't know, and at this point, I'm getting the impression that Mr. Lv doesn't know, either.
"Syngas" produced from coal is primarily carbon monoxide (in fact, ideally, it's 100% CO), and thus is a relatively poor fuel when compared with other fuel gasses. For example, CO has a HHV of around 12.63MJ/m^3, while CH4 (methane, the primary component of natural gas) comes in at about 39.76MJ/m^3. For that reason, "syngas" is frequently used as a feedstock for conversion to other chemicals; on the fuel side, methanol is a common end product, which is mentioned in the PR. Conversion to methanol would be one route to liquefaction, and likely a cheaper route that cryogenic liquefaction of the CO (the latter being the first thought that crossed my mind when I initially read the PR).
They really haven't given us nearly enough information to usefully judge what their plans really are, though, which leaves me wondering whether they a) don't have a clear plan, or b) are simply hiding the ball, as it were.
From today's press release:
"Mr. Lv continued, 'The Facility, located just approximately 78 kilometers from the Company’s coking facility, will also allow us to consume up to 75% of our coke output internally, significantly reducing the margin squeeze on our coke products by steel manufacturers who have been struggling due to industry-wide supply-demand imbalance and plunging steel prices in recent years. The expansion plans for our syngas facilities in Shilong District, Pingdingshan City have been delayed because the current gas pipeline network extends only 10 kilometers from our existing syngas facilities. The Yingqing Facility, with its ability to liquefy and compress syngas for ease of storage and transportation, will allow us to break this geographical barrier, paving the way for a replicable business model for future growth.'”
One would reasonably draw the inference that the government-subsidized pipeline plan has been abandoned. The processing mechanism suggested in the last sentence adds a layer or two of end user cost (compression and/or liquefaction, plus truck or rail transport) that was avoided in the business plan as originally announced.
Until they can be more specific (i.e., whether liquefaction is chosen as a regular feature of their process) it will be difficult to evaluate potential costs.
In the context of direct effects on Sinocoking / Hongli's operations, I'd think the change would be minimal, and limited to two areas:
1) To the extent that China's energy commodities actually trade on a "market" as we understand the term, the fuele price should adjust-in this case, dollar-denominated price lower, RMB-enominated price higher.
2) IF they need to import equipment to complete their in-situ gasification process, naturally, the relative cost would now be higher.
As a practical matter, though, I'm not at all certain that either of these circumstances apply, in which event the effect of the PRC's currency manipulation would be nil.
Evidently, the lowing herd had time to puzzle out the arithmetic overnight.
Just as an aside, BP-Whiting is in PADD II, which includes Cushing, OK storage. If they're down for 10-13 days, that would result in 2.4MMBbl-3.12MMBbl reduction in demand over the course of the outage. I'll be interested to see whether that actually shows up in EIA storage number in the next couple of weeks.
That seems counterintuitive, does it not?
Refinery capacity is already stretched pretty thin (per last week's report, they were running at 96.1% operable capacity during the week ended 31 July). Taking out 413.5Mbbl / day of refinery demand (BP Whiting's capacity) should actually reduce demand for crude oil.
Is there something I'm missing, here?
Hey, Fritz. Hope you're not roasting alive, out there. I have a little side study going on the Columbia Generation Station, and have noted some incredible temperatures out your way. Wish I was invested in a cold beer concession out there.
Your questions are, as usual, incisive. Here's what I think, in order:
1) Probably not. Iran already is allowed to sell a certain amount of oil under the existing sanctions, and I have reason to believe that a considerable amount of additional "leakage" has occurred right along, so I'm doubtful that the end of sanctions translates into a significant increase in oil on the general market.
2) Very probable, but not an absolute certainty. Notwithstanding, I see that oil drillers are moving back into some of the shale basins (at least, according to Baker-Hughes).
3) Near-certainty. Those gold-plated Bentley grilles don't come cheap, and now it looks like they're going to need some little incidentals, such as Paveway munitions, F-16 spares, 105HE, etc..
We're likely reading the same material. One of the fellows over on the Cheniere (LNG) board mentioned a Houston Chronicle article dealing with the subject, which I've read, and I believe covers the points you mention (cost, etc.).
I don't know how much liquefaction capacity is too much, but I know quite a lot is being built. One of my long-time colleagues is an engineer for a firm that builds all sorts of pressure vessels and associated systems (including LNG), and I know that he's been out of the country more than he's been home during the last couple of years specifically on LNG terminal work.
On the other hand, I also keep an eye on shipping, and have seen several articles bemoaning an excess of capacity in the LNG carrier fleet, which presumably would lead to lower rates.
At this point, with ConocoPhillips having the sole recent experience in export of LNG sourced from domestic gas, and that limited to Kenai terminal, I don't believe anyone has sufficient information to begin to predict the eventual impact of the export of domestic gas in the LNG trade.