I believe hjohn529 may have inadvertently missed a week, here. This is the list I saw on First Enercast Financial for this week's report:
SMC Report #$%$br />
Stephen Smith Energy -47
First Enercast -44
Energy Aspects -43
Gelber Associates -43
Tradition Energy -42
Reuters Survey -41
Energy Management Institute -40
Energy Ventures Analysis -40
FirstEnergy Capital -40
Price Futures Group -40
Thomson Reuters Analytics -40
Ritterbusch Associates less than 40
PIRA Energy -38
Asset Risk Management -38
ICAP Energy -37
Raymond James -37
Wells Fargo -36
Citi Futures -35
C H Guernsey -32
As can be seen, the average comes in at around -42, within a range of -32 to -65.
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.
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 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.
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.
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.
Interesting article. Am I reading that publication date correctly? Looks like 25 May 2010. I'd bet it was even more interesting back then.
Before filling (and, more particularly, refilling) any steel cylinder with MG2, I'd strongly recommend that you read "Dangerous Gas Mixtures: Avoiding Cylinder Accidents" by Eugene Ngai (published in the 2nd Quarter 2014 edition of the Specialty Gas Report).
I'd also take a look at an article in the 28 March 2016 edition of the Tampa Bay TImes titled "A year later, fatal Tarpon Springs explosion remains a mystery" by staff writer Laura C. Morel.
The first article addresses not only H2 embrittlement (a well-recognized, if poorly understood phenomenon), but also some additional, emergent steel degradation phenomena peculiar to H2 / CO gas mixtures.
From the Tampa Bay Times article:
Since then, MagneGas created a safety director position and hired Bruce Gane.
"What that did was it made us better," said Santilli of the OSHA evaluation. "Now with Bruce's leadership, we're really following up on everything."
Because the company still can't pinpoint what exactly caused the April accident, it completely changed the way it makes its gas, Gane said.
Instead of using liquid waste, such as used cooking oil, to produce MagneGas, workers now use soybean oil. The company also switched to more expensive bottles.
"Everything surrounding that situation has been changed without anybody coming in and telling us to change anything," Gane said.
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.
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'm looking forward to hearing more of your adventures in blacksmithing. I have a little charcoal / coal forge I made up years (over 30) ago out of 14 3k fire bricks, a bit of fire clay, four pieces of steel angle, and some steel banding. Still works after all this time; I use it to make tools, small blades, and occasionally impossible-to-find parts for antique firearms.
When you get around to your hinges, might I be so bold as to suggest a trip to the grocery for a box of borax? I use the "20 Mule Team" pure borax as a fluxing agent for forge welding. If you really can't live without anhydrous borax, cook a little of this in a 350-400 degree oven for 30 or 40 minutes. Personally, I use it right out of the box (it's hydrophyllic, so it clumps like old-time salt); crush it up with a pestle and sprinkle it on (or dip the workpiece in the powder) before heating; takes a lot of the frustration out of learning to get a good forge weld.
Keep up the good work!
Interesting you should mention linseed oil. That's what I use for quench oil. It doesn't seem to "flare" anything like petroleum-based oils do, and it leaves a very nice black sheen on the workpiece that can be left as a finish (except, of course, for items that need to be polished, such as cutting tools, etc.).
I also use linseed oil as a "first pass" sealant on browned rifle / pistol barrels, followed up with microcrystalline wax.
I use it on stocks, as well, and have even tinted it with artists' oil paint.
I have an old gallon can from Dutch Boy that has the "recipe" for making up paint using white or red lead. We used to add a little bit of Japan drier, as well, because the unadulterated stuff cures slowly, particularly in humid climates.
I'll assume you're referring to the EIA natural gas storage report. (If not, that ship's already sailed for the week.)
I expect a draw, and I expect it to be a bit larger than last week's report. Survey results I've seen indicate an average expected draw of 57 (i.e., -57), within a range of -44 to -63. The five year average for this week (gas week 9) is -138.
Next week, on the other hand (i.e., the report for the current week, or gas week 10) I think could actually see a modest build. We've had a string of really warm days, and even Bentek's daily data suggest supplies just slightly in excess of demand. We'll see.
"I expect some type of unexpect build (or less than expected draw) tomorrow or the next week and hope to get in lower."
Could be; it's certainly been a weird year for weather. In any case, I wish you the best of luck.
One note: Remember, if you're looking at UNG, they will start to roll out of the April contract (and into May) on 15 March, and finish on 18 March. Calculating the notional NAV around their roll dates can sometimes be a bit of a challenge.
Reuters has an interesting piece today (Wednesday, 9 March) regarding techniques shale drillers are using to maximize production at existing wells. Searching for:
"Forget fracking. Choking and lifting are latest efforts to stem U.S. shale bust"
should get you to it.
Incidentally, some of the comments therein illustrate why I wish Baker-Hughes would bring back their workover rig count. We're only seeing part of the picture, and I suspect it's likely that workover rigs are playing a larger role now, with the prevalence of shale wells, than was perhaps the case in years past.
SOCO International announced today that their Baobab Marine I well offshore of Republic of the Cngo came in dry. The well was located in the Mer Profunde Sud block, and was spud on 8 February. When they announced commencement of drilling, they estimated a cost of $25 million to $30 million.
Makes those $6-$7 million shale wells look cheap and tacky, eh?
The Ohio Department of Natural Resources released the 4th quarter 2015 shale oil and natural gas production figures this week. On the NG side of the ledger:
For the quarter, 1,229 wells are represented in the report as producing any quantity of NG. Total production was upward of 302.5 Bcf, with average daily production coming in at 3.288 Bcf. This is an increase over 3Q 2015, which showed 1,085 wells producing above 245.5 Bcf total, or about 2.671 Bcf/d. Year-on-year, 4Q 2014 had 773 wells, yielding about 164.8 Bcf total, or around 1.792 Bcf/d.
The outcome of the NG generation substitution exercise depends on one's assumptions for capacity factor ("run rate"), heatrate, and fuel quality.
Bentek ran a little piece this morning in which they hypothesized a capacity factor of 0.6, and a heatrate of 8.5 (MMBtu/MWh) for NG-fired generators replacing retiring coal power stations. If we apply those assumptions to a 1,000MW capacity retirement, we'd end up with a requirement for 122.4 MMBtu per day.
How that translates to physical units of MMcf or Bcf depends on fuel quality. I think most traders assume a ratio of 1MMBtu per 1Mcf of NG, in which case the answer is a straightforward 122.4 Mcf per day. In reality, the gas received by electricity producers generally has a somewhat higher heat content. The "fleet average" during 2015, for example, was 1.035 MMBtu/Mcf, which would drop our example's daily requirement in physical units to about 118.3 Mcf.