49 comments on US Natural Gas - May 09
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49 comments on US Natural Gas - May 09
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Gail, I am glad to see someone who knows how to generate a post graphs starting to look at NG. the biggest factor in pricing is not supply an or demand at a point in time, but storage. NG has n "injection" (to storage) season, roughly end March to end Oct. (28-30 weeks), and a withdrwawal season of about 22 weeks. Available storage volume has increased duting the last 7 years from about 3.2 Gb to, this year, probably 38.5 Gb. Prices get driven down in the late sunmmer if there is a real risk of storage overflow. Lower prices cause a smal amount of shut-ins and maybe some coal to gas switching, that relieves the overflow risk. Prices tend to go high in Feb. if their is a risk of overwithdrawal. There has to be about 800 Bcf minimum in storage to keep pipelines flowing to end customers. The increases in production in 2007 and 2008 resulted from a huge increase in drilling rigs and drilling starting in late 2005, (I don't have the numbers handy) but total rigs in use increased by a factor near 2 and horizontal rigs by a much larger factor from a much smaller base.
Now we have had a big drop in demand, mainly due to the economy. Drilling peaked in early Sept 2008, and you are seeing that last increase in the early 2009 production numbers. Rigs started to be taken out of production in a small way in late Sept., with a huge acceleration in Nov. and total working rogs are now down about 55% from their peak, with horizontal rigs down nearer 30%. The impact on production should begin to show up in something like 3 to 5 months, ie. now. If the economic recovery is successful and if it starts in late 2009, we will see a resurgence in demand colliding with a major drop in production. I have not tried to quantify the likely drop in production, but I wish that someone a lot more computer adept than me would do so.
LNG will compensate the early production declines, and we will have a huge storage overflow this year, regardless of what gets done. The high storage will ensure adequate supply this next winter, pretty much regardless of how cold it gets. The winter of 2010/2011 will be another story.
NG is the marginal fuel for electricity supply, so it will swing at a multiple of changes in electricity use, which is a major reason for the decline in demand.
I read last year that the minimum price that supports new production development is about $8.25 per kcf, but I don.t know how good this number is.
Tight sands and shale gas is plentiful, but for any well, initial production rates are fairly low, and declines are in the order of 50-60%/yr, so it takes a huge amount of drilling, just to run in place.
The big problem with retiring rigs temporarily is the time needed to rehire and train crews to get them running again. We are in for a really big swings in NG prices. Maybe less than $3.00/kcf by Sept. this year and > $12.00/kcf by Feb. 2011. Murray
I agree that storage is a big issue for natural gas. At least for oil, it is possible to put extra oil in unused tankers and tank farms. For natural gas, there is a very fine line between what we can use, what is too little, and what is too much.
If we had, say, twice as much storage distributed throughout the country, we would have more flexibility in production. But storage is expensive, and takes time to add. I don't think we can count on big changes in storage, without, say, a government program encouraging more storage.
Here's an up-to-date graph of the NG rig count, from Baker Hughes data:
Got parachute? Hope in a year or two those boys are ready to multi stage frac like there's no tomorrow.
I related the other day how Morgan Downey said in Oil 101 that during periods of contango in crude one of the cures for the ascending forward curve is to build more storage - facilities, that is, I'm pretty certain he doesn't mean build inventory. Have to ask Morgan about that sometime, or perhaps he'll see this and elaborate.
We will have to ask him.
It seems like additional storage for crude could be added a lot more cheaply and quickly than additional storage for natural gas. If nothing else, the minimum addition would seem to be pretty big for natural gas.
Gail -- Investment capital will always be an issue of course. But there are also a limited number of reservoirs that are suitable for storage. Most are in the Gulf Coast. Unfortunately the main bottle neck is getting from here up north.
I've been watching folks try to develop NG storage for the last 15 years with very little success. Unfortunately when NG prices are low it's a great time to develop storage since one needs to buy a big NG bank to inject initially. But when NG prices are low there's much less interest in financing storage since the upside appears to far down the road. This might be the one area where the gov't could throw some sort of tax incentive. But how popular would throwing apparent "bail out" money to the oil patch be right now? Of course, the gov't could build and operate new storage. They've done it with the SPR. But that's a pretty simple operation compared to NG storage.
The trick is what do you use for initial production and decline rates? The Canadian NEB has such data for every producing region and each region is quite different.
The Chesapeake model is hinting we will be down a bit more than 3 Bcf/d by early 2010, expanding quickly after that. Credit Suisse estimates that once we hit production bottom, it will take 2 years for increasing rig counts to claw production levels back up to our prior peak.
Figure 1: Future gas production based on final rig count drop
Source: Chesapeake Energy
-Click to Enlarge
Good article Gail!
Gail,
Thanks for an interesting piece.
Jon,
The diagram accompanying your comment is very comprehensive.
If I read it right, then assuming 750 rigs at work, US production may decline to about 56 Bcf/d by spring/summer 2011. US nat gas demand is presently showing some weakness and assuming some supplemental supplies of LNG (though the US nat gas prices presently suggests this will be the LNG market of last resort) and some time for an economic recovery to affect nat gas demand.
Further if Credit Suisse’s estimates are right about taking two years for increasing rig counts to claw back production levels, it looks like the period 2011 - 2013 might be supplied constrained.
My prior comment was poorly worded. The time is 2 years from peak to peak for a simulated shale formation with 80% decline rates (like Haynesville).
The longer it takes for prices to rise back up to drilling costs the worse the drop in production will be and the more severe the price spike later.
Canadian NEB Short Term Deliverability Report
The NEB report has an appendix which lists the decline models and initial production by region. I thought others might like to see what a model might look like.
I only saw this after my last post. It gives .020 Bcf/d/rig/yr, vs my estimated .016. Horizontal vs current mix could account for that difference. This scenario has 6 months down, 12 months flat, 3 months back up and then 3 months at the new plateau. We are now 8 months down. At $7.00/kcf to encourage drilling, (see Rockman) we are surely in for close to a year flat. then it is very unlikely that a ramp up could be done in anything near 3 months. Also a good percentage of the old vertical rigs will be scrapped and have to be replaced. Looks to me like at least 3 years to get back to Jan 2009, and maybe as much as 4. Murray
Jon, that's very interesting and helpful. I had just been doing a "back of the envelope" attempt, and came out real close to Chesapeake. It looks like from 7/06 to 1/09 we went from 53 Bcf/d to 61 Bcf/d, of which 1 Bcf/d was Independence Hub, which we shouldn't use in estimating, so let's say 60. From early 2003 to mid 2005 we went from 700+ rigs to 1100 rigs )mostly vertical) and production dropped about 3% during that period. Mid 2005 to Sept 2008 we increased to 1600 rigs (a good % of the increase were horizontal) and production went up 10%. So it looks like now we need 1100 - 1200 rigs operating just to offset declines, which is pretty consistent with the curve. At about 700 rigs, where we are now, production should be down to 54 Bcf/d by mid 2010 or 10%. Yikes! The increase in horizontal in the mix might help that somewhat. LNG isn't likely to offset more than 1/4 of that decline, and may only offset declines in exports from Canada.
From memory, global USA production decline rates were near 20%/yr in 2000 and 28%/yr by 2005 or 2006, with almost no contribution from tight sands/shale. Now tightsands/shale are a rapidly growing part of the mix of producing wells, and appear to fall off 50 to 60%/yr, so the global decline rate is probably >30%/yr and growing. So 1100 to 1200 rigs must be able to generate new production of 18 Bcf/d/yr, or .016 Bcf/day/rig/yr, just to offset declines. We are now light at least 400 rigs light so will see a decline of roughly 6 Bcf/d/yr, which is pretty close to the rough-cut 10%. During 2008 we had an average of roughly 1450 rigs operating which should have offset declines and added 5-6 Bcf/d/yr which is about what happened, so these numbers seem close enough. Some computer whiz can certainly do a more informative job, but this isn't bad. Thanks muchly.
I think the Horizontal wells may be overweighted i.e when they do decline it will be both steeper and to a much lower end production rate.
Also ROCKMAN has mentioned this a few times here and there but I really question if people are going to put in compressors as pressure falls off. My opinion is that any production needing a compressor is more likely to get temporarily shut in.
So I think production is going to be fairly non linear. Lets see where we are in six months since if these secondary issues are both real and large then they should start to show up within six months of now give what your saying about the number of rigs being dropped.
Next if the oil prices continue to increase strongly there is still significant dual fuel use with NG and fuel oil. This will flip to NG. And also as I've posted before we seem to also have a tight relationship between heavy sour crude refining and additional NG usage in refineries. If the US begins to favor the cheaper heavier sour crude esp with the relatively low NG price then this is another source of increasing NG demand.
I'm going stick my neck out and call a bottom for NG near the current price we may bump around it for another month but I think the bottom is in.
Next I'm going to even stick my neck out further and call for NG to move to the 7-8 dollar range within the next six months maybe hitting 10 or higher if some of my ideas are on the mark.
However I don't think this is going to bring the rigs back. I don't think that the rig count will actually turn around until after we see NG break at least 10 and then only slowly.
So maybe a month bouncing around near the bottom then fairly smooth increase toward eight over the remaining 4-5 months.
I'd not be surprised in the least to see rig counts continue to drop even as we pass eight.
memmel -- adding compression to the wells probably won't be much of a problem except for operators near bankruptcy. Granted, as you say, production has drop to rather low levels at this point. But even if adding compression only offers a very modest return there is another big benefit: you keep the lease active. Most oil/NG leases terminate automatically if a well is shut-in for more then 30 days. If that happens not only does the operator lose the mineral rights but is also obligated to spend $'s to P&A the well. The operational costs come out of cash flow so that's usually not an issue. Buying or leasing the compressor is the bigger hurdle. But if the compression companies have units just sitting in the yard they'll often let the operator pay for it out of cash flow. of course this all assumes there is a net gain of income by going to compression. NG pricing will pretty much control that call.
I agree with you: it's difficult to see rig rates improve significantly even if NG comes back up to $7 or $8/mcf. The NG players are hurting from a cash flow perspective. Add that to being badly burned by the rapid expansion of drilling followed by an even more rapid collapse. The mindset I hear around the coffee pot these days is that they won't be so fast to jump back into water.
Memmel, the problem in the next few months is storage. We will have enough supply to put at least 4.3 Tcf into storage by the end of the injection season, but only have storage capacity for 3.85 Tcf at the most optimistic. Prices will tend to drop to increase demand, and the only real temporary demand increase is coal substitution, which will require a price at or below $3.00/kcf. Some wells may be shut in, but that seems to be a choice of last resort. Rockman can provide enlightenment on that subject.
At 3.85 Tcf in storage, and line pack at max., we will have plenty of NG to get through the next withdrawal season, with high enough storage that, at even 2007 production rates, we would get to fairly adequate storage by Oct 2010, so for some months there will be little pressure on price. However, by maybe late June 2010 it will start to become evident that supply is declining, and adequate storage refill is doubtful. At that point the bidding war for the available supply will start. In Sept. 2010 there is likely to be something close to panic as storage goals get unmeetable. I would guess that there will be delivery failures due to low supply by late Feb. 2011.
Price should stay between $3.00 and $7.00 until about 6/10, and then start to rise. Sept. could see anything from $10.-20. The last time we came close to supply failure, (Q1 2003), prices went to $18.00 interday, and $28.00 for a brief spike intraday.
My "back of the envelope" conclusion is that for the year from end March 2010 to end March 2011, supply will be between 1 and 2 Tcf below demand. One Tcf would bring Q1 2011 storage to a dangerously low level, and 2 Tcf would wipe out storage altogether. Of course, that can't be allowed to happen, so price will go high enough to decrease demand and increase supply, which can lead to an extreme short term spike.
I think Rockman is right about the reluctance to get back into drilling in a big way until it looks like high prices are here to stay, which means fairly delayed return to Sept 2008 capacity. From 2005 to Q3 2008, rig count grew by near 200 rigs per year. I think the highest 12 month period was about 240 rigs. Even at 200 rigs per quarter from Q3 2010 on, my scenarion would likely develop. Murray