"...a short squeeze is the only thing that can send NG up at this time."
I think you're absolutely correct. Unfortunately, I imagine that would provide only ephemeral relief, good for a quick trade, but nothing in the way of a foundation for a longer term position.
Thanks. There was one additional respondent on a list that I saw today: Price Futures Group, calling for -67. With that included, the arithmetic mean is around -41.
I'm thinking that, if they make it through this week, this will drag on into the new year. Not on any merits, mind, but merely due to bureaucratic lethargy owing to the holidays.
Yes, I have, although for me it's a case of "once bitten-twice shy" (I got on the wrong side of a couple of PV trades back in 2012-2013).
I've been looking not only at SUNE, but their TERP spinoff. Haven't worked up the nerve to take a position in either yet, though. Maybe after the first of the year.
While I'd agree that there will ultimately be more NG-fired power generation in coming years, I'm not so confident that it's going to make a seismic shift in the near term. An excellent case in point is an article that came out yesterday concerning a PPA fight in which American Electric Power (AEP) has been engaged for months now. (Enter "AEP Sierra Club" as a search term and it should take you to the complete article.)
The short version is that AEP has agreed to "...close...OR ... convert..(to fire on NG)." two of its existing plants (total of about 1,503MW capacity) by 2029 or 2030.
In the meantime, they are committed to adding 500MW of wind generation, and 400MW of photovoltaics, with RFPs for the latter to be issued "within 45 days.".
The obvious implication, naturally, is that near-term, fossil capacity of any sort will be displaced by these renewables. Moreover, this is hardly an isolated case. Bentek has had one or two articles a month noting displacement o NG-fired capacity by wind and photovoltaics in California and Texas.
I can't speak to UGAZ. My understanding is that, because they operate as a ETN, they don't hold contracts for physical gas, but rather are based on index-linked derivative instruments.
UNG, on the other hand, holds contracts for physical gas exclusively; a combination of NYMEX and ICE contracts. I've tracked UNG's assets base very closely for many months, and, like you, have noted that the NAV really isn't much influenced by contango around the roll dates. If one follows their assets exchange over the course of their four day rollover periods, the reason becomes apparent-regardless the price of the respective contracts, ultimately the NAV is determined by the total cash value. For example, let's say they have 20 fund shares outstanding, and 20 "Month 1" contracts worth $1.00 each, the NAV is $1.00 per share. If they sell 10 "Month 1" contracts at a dollar each, and the "Month 2" contracts are two dollars each, then they simply buy 5 of the "Month 2" contracts. The cash asset value is still $20.00 (10 "Month 1" contracts at $1.00, plus 5 "Month 2" contracts at $2.00); the fund's share count remains unchanged, and so does the NAV. (This is an over-simplistic example, of course, but you get the idea.)
The problem for many traders comes after the rollover is competed. This month, for example, there will be six trading days following the rollover on which the commonly quoted Henry Hub price will still be on "Month 1", while the fund's NAV will actually be based on "Month 2". To the extent that these diverge after the roll dates are completed, any rationale for a trade based on UNG's technicals prior to the roll will have changed.
Remember that UNG starts to roll over to the February contract tomorrow (15 December) and will be entirely dependent on that contract (and therefore trading independent of the January contract) by close of business Friday.
i've read the same regarding GoM refiners (and, likely, others in the U.S. as well).
The question in my mind is, "Why would anyplace else in the world be better equipped to refine our light crude?" We haven't exported this in decades, so I don't see any reason why any refiner beyond our borders would elect to design a refinery targeting WTI or light, sweet crude.
We grilled steaks out back on Saturday evening. That wouldn't be all that unusual for me this time of year; I've been known to do that with snow on the ground. This year, though, I was sitting around in my shirt sleeves drinking beer. I'm told we set a new record high for the date.
I'm about the last fellow here who should be fielding that question.
Ordinarily, I'd say that I'd expect the day-ahead markets to flatten out, or even bounce back up a bit, early next week, simply because of the dynamics of lower demand over the week-end. Now, though, there's quite a bit of downward momentum, which may prevent that.
It's been an interesting week for the ICE day-ahead prices. First, here are the Henry Hub figures for the week, including price range:
Start End Volume High Low VWAP
12-05-15 12-07-15 351,000 $2.15 $2.07 $2.09
12-08-15 (Same) 268,000 $2.05 $2.02 $2.03
12-09-15 (Same) 157,000 $2.00 $1.95 $1.98
12-10-15 (Same) 360,000 $2.01 $1.98 $2.00
12-11-15 (Same) 319,000 $1.96 $1.85 $1.91
12-12-15 12-14-15 260,000 $1.80 $1.73 $1.77
The average for the aggregate of all North American hubs is even more telling:
Start End Hubs Volume VWAP
12-05-15 12-07-15 106 44,913,000 $2.0480
12-08-15 (Same) 107 47,509,000 $2.0118
12-09-15 (Same) 107 50,328,000 $1.9307
12-10-15 (Same) 104 50,441,000 $1.9447
12-11-15 (Same) 106 51,656,000 $1.8440
12-12-15 12-14-15 109 52,126,000 $1.6111
Note that the "Hubs" column (three digit figure) represents the number of hubs quoted for a given flow date.
Right off hand, I can't recall when the last time was that we had a day ahead priice this low across the board.
From what I can see, the Baker Hughes oil / gas split data extend back to mid-July of 1987. That 185 gas rigs figure is currently the all-time low. The period average is 678. Even given that these modern rigs appear to be far more productive in terms of their ability to complete a well in a shorter time period, I can't help but think that we must be approaching the point at which this reduction in drilling activity will begin to manifest itself in production figures.
The fellows whom I know down here that farm fall into two categories-"hobby" farmers (less than 500 acres) or really large operators (3,000 acres or more). Those who grow corn generally use it for animal feed exclusively, or plant sweet corn for sale as "green" corn in the summer.
Some of the large operators have land in the Conservation Reserve Program (which, I assume, is the program you mentioned). I really can't debate the wisdom of it, but will note that it has made for good hunting opportunities for me personally, and has the added benefit of allowing some of our upland game species to rebound (noteably bobwhite quail, which were nearly exterminated down here in the extremely cold winters of the late '70s).
I suspect that, if it was simply a matter of sending grain off on a dry bulker, we'd be sending more around the world to poorer nations, but it isn't that simple. In Africa, particularly, many of these places are landlocked, and lack the transportation infrastructure to distribute bulk commodities on such a scale. The expense of such charity therefore grows by an order of magnitude; we'd need to also build the transportation and storage facilities, provide the materials (typically there's no industrial base), at least in the early going, provide the technical personnel, etc.. All are possible, of course; all it takes is money.
I think corn-based fuel ethanol is a lose-lose proposition. Some time when you have a few spare minutes, look up Greater Ohio Ethanol (bankrupted in 2008, subsequently sold off) in Lima, Ohio. They underestimated their process water requirements by an order of magnitude, and ended up having to truck in additional process water (city service couldn't keep up).
Another outfit bought them out, and is now operating, but it remains to be seen whether they can make it work in the long haul.
I could be a whole lot more supportive if they'd just turn all that into corn liquor. Far more useful stuff.
I haven't had any fuel line problems, but have had a number of priming bulb failures on my 2-sroke tool engines. One of my neighbors collects vintage motorcycles, and we've seen some carbuerator gasket / diaphragm failures in those, as well.
We started searching out marinas and small airports that still carry unblended (0$ ethanol) fuel. For these applications, where you're only buying a small quantity of fuel over the course of a season, it doesn't add a lot to the fuel cost, and saves the headaches of replacing the lines.
I'd also note that true, buna rubber fuel lines seem to be little affected; I have the most problems with the vinylester lines / bulbs.
"If only the price of a new 4x4 pickup go under $20K."
Won't happen so long as city folks want pickups decked out like town cars.
Once upon a time, I had a '73 Dodge Power Wagon, 1-Ton chassis, 360 V8, M48 locking hubs, no options whatever beyond an AM-FM radio. Paid $3,100 for it in 1976, with, I think about 48k miles on it.
Ran it until 1994; had replaced the original bed with a channel iron and 2x12 flatbed (original rusted out). By 1994, it had a hole in the cab floor that my dog could use to let himself in and out of the truck.
Wife made me sell it. Every time I need to do a big job around here, I miss tha truck; if I could have scrounged up a decent cab, I'd still have it. Ran great, even got decent mileage (19-20MPG) on the highway with the hubs locked out.
Based on the figures above, I'd make it to be around 53 Bcf (pretty close) to 71 Bcf (markedly higher) per year. Naturally, nobody knows right now what their capacity utilization rate will ultimately be. For all I know, the bottom could fall out of the market for ag ammonia next year; I'm definitely no farmer.
I don't find any direct estimates. However:
OCI, in another presentation, represents that their process consumes "...about...1,000 m^3..." of natural gas per tonne of ammonia yield. One m^3 of NG is about 35,315 ft^3.
The Wever, IA plant is represented to have a capacity of 1.5 to 2.0 million tonnes of ammonia annually.
To me, it appears that the plant will require roughly 0.145 to 0.194 Bcf / day.
As a matter of interest, I saw a Reuters piece claiming that the first vessel to fill at Sabine Pass will be Energy Atlantic (IMO 9649328). This is a newbuild, 290 m long, with a 46 m beam. At 91,800 DWT, I suspect Energy Atlantic has more like 170,000-180,00 m^3 LNG capacity, but I haven't seen a definitive figure for her yet.