Here are a couple of other points to ponder:
The 2012 "injection season" ended right on schedule, at Week 44, on 2 November 2012. Gas stores at that point amounted to 3,928 Bcf, which was the all-time record until this past year.
Notwithstanding, 2012 set another record-daily average injections during the "season" came to only 6.55 Bcf/d, the lowest recorded in the period 1994-2015. (Current daily average is 7.26 Bcf/d.)
The summer of 2012 also had the distinction of being exceptionally hot, with several population-weighted Cooling Degree Day figures exceeding 100 in the July-August period. Ironically, that caused a few fairly widespread power outages, which likely mitigated the power burn.
Because this year so far is looking very much like 2012, I ran a little hypothetical exercise to see where we'd be if we follow the 2012 injection pattern for the rest of the season:
Week INJ STORES
26 39 3179
27 33 3212
28 28 3240
29 27 3267
30 27 3294
31 23 3317
32 21 3338
33 47 3385
34 66 3451
35 28 3479
36 27 3506
37 67 3573
38 80 3653
39 78 3731
40 72 3803
41 50 3853
42 67 3920
43 64 3984
44 21 4005
The week just reported was Week 26; typically the injection "season" ends at Week 44. NG volume units are Bcf.
The pressure test seems prudent.
Of course, I don't know how things work in your world, but if we did that in my shop, I can pretty much guarantee that the instant we fed it the air, we'd discover that we'd overlooked some obscure vent, plug, or hole, which would announce its presence by coating us with oil. Nothin's ever easy around machinery.
Interesting. Are you certain that the workpiece is Al? If it's European (particularly VW / Porsche) there's a good chance it's Mg, or at least a high-Mg alloy. Al rods tend to flow poorly on these.
I expect Alaska's daily average to be down considerably in next week's report, as well. As of right now (figures through the 27th) it's off around 240 MBbl/d.
My suspicion is that maintenance (either planned or emergency) is behind it, because the drop is sudden and severe. Further supporting that notion is a pattern of similar production drops at around this time in years past.
Whatever the cause, my expectation is that overall domestic production will be much reduced in next week's report.
I believe the best answer is a qualified "Yes", there is plenty of existing generating capacity.
The challenge is getting the electricity where it needs to be in the face of heat-induced transmission and distribution equipment failures. A considerable number of power stations rely on connection to the grid for field excitation, and, if a section to which a station is connected has difficulties due to temporary heat-induced damage, it takes the power station with it. Power from other stations often gets re-routed around the failure, which leads to increased load on other sections of the network, and cascade failure is the worst-case result.
In fact, I can't think of any widespread outage in the last 40 years or so that didn't start in this manner.
One occasionally sees localized outages with other causes-for example, according to Bentek, SoCal curtailed some gas deliveries to utility generator customers in SDG & E territory yesterday, but it's likely that SDG & E dealt with that through a combination of electricity imports and demand-side management (DSM) actions. DSM is becoming an increasingly popular tool for load mitigation; I suppose one might characterize it as a sort of mutually agreed "blackout" for which the customer receives compensation.
trader537 is almost certainly better qualified than I to weigh in on this. With that in mind, and looking at my own collection of daily cash market data (aggregated to monthly basis), for what it's worth:
It appears to me that we may have another month of upward pricing pressure, although I'd imagine the rate of change will moderate. My impression is that the somewhat lower (as compared with the last 3 years( storage injections are being interpreted as modest supply constraint. I personally believe this interpretation is incorrect; production may be currently lower than, say, the peak in 2014-2015, but it's hardly faltering, and I suspect that storage operators are reluctant to take gas at a much greater rate than at present.
I'm also mindful that, while we're not yet seeing a rush to drill in either the oil or gas fields, the mass exodus seems to have halted, and the Permian, particularly, is gaining some rigs. Drilling there undoubtedly means an influx of oil-associated gas that is right where it needs to be geographically to affect Henry Hub pricing.
Wish I knew. I've read a number of articles over the years that discuss the various factors that enter into determining the cost of storage, but I've never found any good source of hard figures on an incremental basis.
One reason may be that different types of storage command different prices (just as baseload and peak load in the power markets differ), but I'm sure there are other factors as well.
Here are the latest figures for regional NG storage capacities per the EIA. These figures were published in March, and reflect mandatory survey responses from storage operators in November of 2015 (i.e., at the end of "injection season"). The raw data I used to compile this is field-level storage, representing altogether 408 individual storage field in the contiguous U.S.. It includes 23 fields classified as "inactive", so presumably, there is nothing left to take up any excess. Units are Bcf.
Region Working Total Daily
EAST 1071 2195 24.5
MIDW 1229 2718 28.2
MNTN 462 913 3.9
PACF 416 678 10.1
SCEN 1547 2640 51.3
Lw48 4725 9145 118.2
Note that "Total" includes Base Gas, which must remain in the storage field to maintain service pressure. If you wish to determine base gas, simply subtract the "Working Gas" figure from the Total.
"Daily" represents the maximum than can be delivered from the field in a 24 hour period. The EIA does not, unfortunately, provide any figure of maximum daily intake, which would be useful to us in our discussions.
The "Inactive Fields" mentioned above account for only 108 Bcf of total capacity, and around 65 Bcf of working gas capacity. Daily delivery is hypothetically limited to 0.58 Bcf/d, but that includes several fields classified as "0" for both working gas capacity and daily delivery.
Finally, there are, in the South Central region, storage fields characterized as "Salt" or "Non-Salt" 0the latter may be either aquifer or depleted field storage). Figures for these are as follow:
Class Working Total Daily
SALT 486 697 32.5
NON-SALT 1061 1943 19
"a 1150 MW nuke just came online in Tennessee"
That's Watts Bar 2. They commenced low power testing on 24 May. I'm waiting to see them take it over 90%, which would indicate that it has passed commissioning; so far, 28% is as high as they've run it (yesterday and today).
Gas storage is pressurized storage, and I believe that the limit of working gas storage is the upper limit. If you look at the storage capacity ratings, you'll see two figures-one for "base gas", and one for working gas. As I understand it, the "base gas" figure is the minimum that can remain in storage and still maintain service pressure.
From the API this afternoon-
Crude oil stores, up 1.518 MMBbl (analyst survey expected a draw of 1.4 MMBbl).
Gasoline stores, 2.254 MMBbl build.
Distillate stores, 3.725 MMBbl build.
We are in summer driving season, are we not? Did I sleep through it?
It certainly seems to be shaping up that way, doesn't it?
I've often heard that history does not repeat, but frequently rhymes. Personally, I'd be content to leave out the ridiculously hot summer we had in 2012; we had a line of storms that came through here around 4 July that year, and were without power for a solid week thereafter.
I'm beginning to believe that high storage numbers at the end of winter heating season breed a reluctance on the part of storage operators to take on significant amounts of gas. Realistically, if the EIA has the numbers right, the South Central region is over 92% of capacity (working gas) as of last week's report. The other regions seemingly have plenty of space (for now), but I don't see how that helps Henry Hub futures; they're first and foremost tied to that South Central region.
Well, XIN0U didn't quite make it to 15,500 (topped out last Wednesday at 15,440.58) before starting back down. HKE was closed Thursday for the Tuen Ng holiday (mainland PRC was closed Thursday and Friday), but XIN0U moved down both Friday and today (closed today at 14,724.50, with intraday low of 14,634.49).
I think it's likely to reverse before 14,000, but, if it falls through there, I'm still thinking the "floor" is around 13,000. Admittedly, I've lost more than one beer on such bets over the years, and expect to end up buying more than one round in future, so I'll not claim any particular expertise, here.
It isn't exactly a mad rush for drillers to get back in the oil patch, but it probably does tell us something about the price point at which they stop running the other way.
Also, the rebound in Canadian rigs suggests to me that the recent, severe decline there may have owed much to the wildfire situation in Western Canada.
Gas rig activity in the Marcellus and Utica / Point Pleasant formations still looks fairly weak, though.
No, I'm in Ohio. Closest I ever got to the PRC was Cambodia about 40-odd years ago, and that was near enough to satisfy my curiosity ion the point.
I actually trade FXI occasionally (and, less frequently, FXP).
My preference is to track the FTSE Xinhua China 50 (formerly China 25) index, which is the nominal basis for the FXI / FXP trade. From where I sit,. it appears to me that the index is rattling around within a range of around 14,000 to about 15,500, and is currently at roughly the midpoint (closed on 2 June at 14,963.96), and trending up. Support below 14,000 is at around 13,000, but the 15,500 looks to me like a fairly hard "ceiling" that would take quite a bit of momentum to pass.
So, not much upside, but my suspicion is that the downside is more like -13-14% (if it goes to 13,000). Still quite a haircut, if you're long, but a ways from -50%.
Here's a "for what it's worth" observation-
Back in January, I started keeping track of USO on a daily basis. This is for me simply a mathematical exercise to gain a better understanding of how they conduct their roll transactions; I really don't plan to trade this. However, it also has the advantage of giving me a day-to-day picture of their internal workings.
As of 5 January, they had 284,100,000 fund shares outstanding. The controlled 84,553 CL contracts worth $33.92 / Bbl, yielding a NAV of $10.095 / share of USO. Through the remainder of January and into February, as you'll recall, the CL futures price trended downward, into the $27.00 plus range. During that time frame, the USO share count climbed, finally peaking at 438,900,000 shares out on 16 February, and controlled 116,938 prompt month contracts. The CL contract (April) on that date was at $30.97; this was two days following their contract roll, during which, coincidentally, the low water mark for the futures share price was reached.
Since then, the Authorized Participants (who dictate the creation and redemption of fund shares) have steadily redeemed shares, so that as of yesterday the share count was 285,100,000 shares out against the (July) contract price of $49.01; they currently hold just 69,408 contracts.
I'm inclined to think that the Henry Hub cash basis pricing we've seen over the last few weeks reflects transportation problems more than a decreasing availability of individual wells' production. Yesterday saw a big spike, for example, but that came on the heels of the Brazos River flooding stories, so to me, at least, the likely price driver is temporary loss of transportation resources.
Both cash and futures pricing in the heart of Marcellus / Utica territory have remained fairly stable. That's not to say that eventually the lack of new drilling activity won't manifest itself in reduced production, but I think we have a way to go before the pricing gets pulled up as a result.