The Fed has made no secret of their desire to have an inflation rate of 2% or so, and have maintained this position for some time now. The current rate ( yearly average vs yearly average) sits at 0.16%. (The Y-o-Y rate for 2014-2015 came in at 0.12%). Naturally, this is based strictly on figures through the end of the first quarter of this year, so the rate will undoubtedly change (likely upward) as the year progresses.
Personally, I'm not much of a rock fan, but am perfectly contented to sit on the back porch and drink beer, or maybe grab a pole and go fishing.
While we're on the subject-
Cheniere's first ever export via Asia Vision showed up this week in the FERC's import/export reporting.
For reasons best known to Cheniere and the Feds, the shipment was classified as a "split cargo", consisting of 1,993,109 Mcf domestically-produced NG, and 1,290,482 Mcf imported LNG held for re-export. (The figures here reflect dry gas equivalent volume).
Prices weren't provided, which is very unusual (first time over the course of five years' worth of continuous records I've seen that).
Cheniere's Sabine Pass terminal has loading berths for two ships. However many liquefaction trains they may eventually have up and running, they can't berth more than two vessels at one time.
I believe the last cargo to sail was in Creole Spirit, departing this past Monday / Tuesday. As of earlier today, the loading berths were empty.
"China is back in the headlines with steel being up and especially rebar which is a sure sign of new construction in Asia."
Possibly. I am mindful, however, that the PRC has one overweening problem-finding employment for staggering numbers of job seekers-and that their attempts to solve this often lead to unusual, and sometimes bizarre, production choices that distort the true economic picture.
Recall that they went all in on photovoltaics in the 2009-2012 period, and ended up flooding that market by channel-stuffing. The end result has been a slew of bankruptcies in that industry all over the world (including in China).
They have gone on a construction spree that has left massive, unoccupied tracts of new buildings, even to the extent of creating virtual "ghost towns".
They are similarly engaged right now in overproduction and dumping of steel products other than rebar, so I'm inclined to be skeptical as to whether the rebar production signals anything more than one more full-employment scheme fostered by local (Communist) Party bureaucrats.
For billyhart and others who may be interested-
Below is a comparison of final prompt month settlement prices for Dominion-South Point (DSP) and Henry Hub (HH) for the past few months (NOV-MAR). I've also included the average daily production figures for Pennsylvania shale NG producers (Bcf/d) from Pennsylvania's OGRE data server. (Note that March data are not yet available, thus the "na" for March in that column.)
Month Bcf/d DSP HH
NOV 13.070 $1.235 $2.033
DEC 13.423 $1.508 $2.206
JAN 13.962 $1.300 $2.372
FEB 14.384 $1.370 $2.189
MAR na $1.000 $1.711
As can be seen, production levels gained steadily, regardless the relative price movement. Now, granted, they may or may not be profitable at these prices (particularly at the local, Dominion-South Point price structure), and I'd be willing to bet they certainly weren't happy with the price, but they obviously were still willing to increase production notwithstanding the price.
I think it's worth asking whether hedging based on Henry Hub pricing is even relevant.
A considerable portion of the Eastern shale production (notably Marcellus and Utica / Point Pleasant) has little hope of participating in the Henry Hub futures market. Based on volume, at least, the best analogue for these producers may be the Dominion-South Point hub, which generally commands only around two thirds the price of Henry Hub for a given futures contract.
As we've already seen, the existing producers there don't seem to be deterred by the current pricing environment, so a rise might actually serve to bring some of the DUCs into service. If Domiion-South Point goes to $3.00, the driller might even start to get interested again.
I don't think there's anything really to support it. My recollection is that we had a similar bump last year roughly at this time, driven partly by maintenance, and partly by expectations (incorrect, as it turned out) of a massive power burn over the summer due to coal power station closures. I don't think either argument is any more supportive of a higher NG price now than it was then.
In fact, I'd posit that local, temporary supply constraints due to maintenance almost guarantee a price drop in future-there's no change in availability of gas at the wellhead, they just can't get it to market, which tacitly amounts to increased storage.
I also note that, in the last couple of days, the Henry Hub prompt month has outrun the cash settlement price, so I'd imagine the contract will pull back.
According to what I saw in Reuters today, Kuwait's total normal production is around 3 MMBbl/d, and the strike currently has them down to 1.1 MMBbl/d, so the net loss is 1.9 MMBbl/d, which seems to me insignificant. (in fact, seems to me you could lose Kuwait entirely and they'd scarcely be missed.)
There's probably enough oil sitting in backlogged tankers to make up for a week or two of Kuwait's reduced production.
Interesting article. Am I reading that publication date correctly? Looks like 25 May 2010. I'd bet it was even more interesting back then.
Is that zero for the report we'll see on 21 April? If so, it's likely a pretty good bet. CONUS popularion-weighted heating degree days for the gas week to be reported Thursday came in at 92. Gas Week 10 had 91 HDD, and ended with a draw of 1 (-1).
MagneGas ought to consider joining the AWS. A "Welding Distributor" membership costs only $540.00 per year, and makes a nice little bullet point on the resume when you're dealing with folks in the industry. The AWS will prorate your dues if you have employees who are individual members.
I looked today, and found Airgas, Air Liquide, Linde, Praxair, etc., but neither MagneGas nor ESSI seems to have a membership at any level.
Bentek had a piece today on the subject. According to them, LNG spot in Asia has fallen to around $4.00 or a bit more; they seemed to believe this was due to falling demand in the face of oversupply.
Again according to Bentek, the expectation was that U.S. LNG producers (and particularly Cheniere) couldn't afford to ship to Asis for that price, so they expected near-term shipments to be limited to South America.
Since our discussion yesterday, I found another interesting piece; a presentation by Tang Limin of the Sichuan Province Development and Reform Commission titled "Current Situation and Opportunities of Sichuan Shale Gas Exploration and Development", evidently first given at an event in 2014 sponsored by the United States Energy Association.
I also went back over GURE's figures from their 7 May 2015 press release, particularly their figure for well pressure. That is telling, and is a good indication that you're probably correct in your belief that GURE isn't exploring a shale play. The pressure argues for a depth around the 1,000 meter area, while, according to Tang anyway, typical Sihcuan shale plays are more like 4,000 meters deep.
Billy, that appears to me to be a really good bet.
Given where we are now, and assuming strictly average injections, we'd be at or slightly over 3,000 Bcf in storage at the end of May. Taking the exercise out to Week 44 (the typical end of injections), average injections would end the season in the 4,500-4,700 Bcf storage range. I believe that's fairly close to the limit of working gas capacity, is it not?
Give it a day or two.
Personally, I'd characterize the reports we're seeing in the last couple of weeks as "inconclusive", leading to a directionless market. Bentek as of today seems to think we'll see another small drawdown (and I think that's entirely possible, based on the ebb and flow of heating degree days lately).
I'm inclined to think that we saw the bottom of withdrawals last week, with storage at 2,068 Bcf, but am mindful that we had a draw that week of 25 Bcf on a nationwide HDD average of 112. The current forecast is for 98 HDD this week, which is right on the cusp of another potential draw.
I reckon we'll see next week.
You may be correct. If they are drilling conventional wells, though, the cost ought to be a fraction of horizontal (my figures were assuming horizontal, hydraulically fractured wells).
The decay curve for a conventional well isn't as steep, but then again, the initial production is typically a lot lower, as well.
I reckon we'll see, by and by.
I have no idea of what the productive life of a gas well in China may be. I'm assuming that they are contemplating horizontal wells simply because of the depth, but even that may be an erroneous assumption.
All that said, here in the U.S. the productive life of a hydraulically fractured shale well can be surprisingly short. Ohio and Pennsylvania (Utica / Point Pleasant and Marcellus) wells I have tracked decay at a non-linear rate, losing about 50% productive capacity in the first year, down to around 33% annual capacity loss in Year 2 for Utica; Marcellus is similar in Year 1, and slightly greater (about 36% decay) in year 2. Marcellus Year 3 is around minus 28%; I don't yet have Year 3 statistics for Marcellus.
The point is, of course, that productivity decay in shale wells is fairly steep, yielding a relatively narrow window in which to recoup costs. So long as the commodity price stays up, that's perhaps manageable, but when the price drops as it has here in the last two years, producers can suffer mightily.
As I've noted before, I don't have a dog in this hunt, but I am curious to see how they do going forward with development of their natural gas assets.
With that in mind, I do have a question-Just how much does it cost to develop a gas lease in China?
Here in the U.S., we're at around $5 million to $7 million to complete a typical shale (horizontal) well. Naturally, some cost a bit more, and some a bit less, but if you follow the reporting filed by producers (e.g., Chesapeake, Rice Energy, Range Resources, Cabot, etc.) I think you'll find that most are in the range I described.
Producers typically don't have much in the way of leasehold infrastructure costs beyond that, with the possible exception of costs of connection to collector lines. The raw gas is processed at a centralized location, with contaminants removed, and useful condensates taken off for sale. If each producer was required to have a processing plant at the wellhead, we'd all be heating with coal or wood.
So, how much does it cost to get a well drilled in China? Let's assume they're terribly inefficient (not a likely scenario, given their demonstrated technical acumen in other fields) and double the completion cost. They ought to be able to get a well completed for $15 million or so. Why, then, do they believe they need tens of millions to develop this?
It seems to me that there may be something else at work here, quite possibly beyond the control of Gulf resources.
Here's what I have on a Bcf/d basis, derived from the EIA's monthly dry gas production report (Sourcekey N9070US2):
Month Bcf/d NET Imports
Jan-15 73.1 4.3
Feb-15 73.6 3.9
Mar-15 74.1 3.0
Apr-15 74.5 2.5
May-15 73.8 2.1
Jun-15 74.3 2.1
Jul-15 74.6 2.2
Aug-15 75.0 2.0
Sep-15 75.4 1.4
Oct-15 74.3 2.0
Nov-15 74.2 2.1
Dec-15 73.8 2.1
I've included the net imports column to provide a picture of overall supply.
If Bentek has it right, we're currently in the 71-72 Bcf/d range for dry gas production, with gross imports around 5 to 6 Bcf/d.
EIA figures for January 2016 (latest available) have dry gas production at 74.2 Bcfd/d, and net imports at 3.4 Bcf/d. January gross imports were 8.8 Bcf/d, according to the EIA.
I think at this point it's a foregone conclusion that we begin injections with over 2,400 Bcf in storage. If injections follow average (2,098 Bcf for the season) it appears to me that we'd actually be in storage capacity constraints as we approach the end of injection season.
Seems to me that makes your bearish case more likely.