Natural Gas Is Heading to 1997 Levels, Should Stay There Awhile 41 comments
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Dispatch From the Marcellus: Natural Gas Prices and the Shale Paradox
In the middle of this decade, E&P companies were spurred on by rising commodity prices and easy credit to find and develop new sources of domestic natural gas–most notably shale gas. The forces that enabled this phenomenal growth in domestic gas production–the great asset and credit bubble–have vanished into air, into thin air.
Now, shale-gas companies may have been impaled on their own bayonets. Yet some would have us believe that natural gas prices are poised for a great comeback–that all the fret and worry is for nothing because prices are going to come right back up and justify the development of all the shale in the country, and then some.
They are wrong: demand will continue to be weak and supply will not be nearly as sparse as some of the gas bulls would have us believe. Instead, the story of 2009, 2010, and beyond will be not only how much farther natural gas prices will fall, but also how long prices will stay in the basement, and who will be counted among the casualties.
The Fallacy of the Rig-Laydown, Production-Decline Pricing Idea:
U.S. producers, loudest among them being Chesapeake (CHK), are howling that lower prices will eventually lead to less production, which in turn will severely impact supplies and raise the price.
But this is not a process which will lead to sustained greater prices, because even if this phenomenon caused a temporary or seasonal price increase, that would only encourage more production from known, vast shale supplies, and other prolific domestic sources like deep Bossier–which would result in another glut, and bring prices down again. In this scenario, wouldn’t the price just settle at a point which is only marginally better than the cost of production? Its also important to recognize that it takes less rigs actively drilling now to produce more gas than even a few years ago.
With more built-for-purpose horizontal shale rigs active in places like the Marcellus shale, a few new, successful horizontal units can bring forth a level of production that may have taken 10 or 20 vertical wells to equal only a few years ago.
For example, to date, CXG has drilled 5 horizontal wells with costs declining from $5.3mm for the first well to $3.8mm for the fifth well. The company expects the next horizontal well to cost ~$3.6mm. Average IP-rate for the first 5 horizontal wells was 4.3 MMcf/d. If we assume the lower horizontal well cost of ~$3.8mm with a 3 Bcfe EUR on 40-acre spacing
Another factor which could cut short a price spike is that gas companies may have wells they have shut in and are not producing. They will turn these wells on as prices rise, allowing a rapid flood of natural gas to enter the market much faster than an increase in drilling could respond. It is also likely that if storage reaches capacity there will be no choice but to shut in some production.
In any event, a slight rise in prices into the zone of marginal profitability would likely engender a race to bring on more production in order to realize cash-flow, which could flood the marketplace once again, causing the price to settle at or near the break-even point. In this shale-supply driven scenario, prices will go to the marginal cost of production, so any industry gains in efficiency and cost-saving of production will only serve to drive the price down.
In the shale-supply driven scenario, big regional shale leaders like Range Resources (RRC) could continue to make money producing high volumes at prices at or near the marginal cost of production, especially since Marcellus gas is usually sold at a Nymex premium in the Northeast market due to savings on transportation.
But this scenario does not factor in the burgeoning supply of natural gas headed to the U.S. on foreign-flagged tankers that can deliver as much gas in a month’s transport time as a good shale well can deliver over its entire productive life.
LNG and the Coming Wave of Cheap Foreign Gas
Another product of the price bubble in recent years that has gone unnoticed by many Americans has been the massive new development in overseas gas fields. Unlike previous years, this development will affect the price of domestic gas because the increase in U.S. import/gasification facilities in the coming months and years means NG is becoming a global commodity. The last few years have seen a significant growth in the availability of liquefied natural gas (LNG) as both liquefaction facilities and available tanker numbers increase. The world’s LNG supply capacity is expected to grow 25% this year, and global demand will not match this increase.
Therefore, LNG will be available to come into the American market. The United States tends to be the LNG market of last resort, as producers send LNG to the higher paying Asian and European markets first.
However, global LNG demand and prices have fallen, leaving more LNG for the United States, whose extensive storage and pipeline network means it can absorb LNG even at times of low demand. “It’s completely counter intuitive,” said Murray Douglas, a global LNG analyst with Wood Mackenzie in Houston, who is predicting U.S. LNG imports will grow 30 percent to 456 billion cubic feet this year and to more than 1.1 trillion cubic feet by 2013. “We don’t believe Asia and Europe will be in a position to absorb this new production, and the U.S. is the only market that can take it, that has a large amount of storage.”
LNG can be competitive priced as low as $3 per million British thermal units (and perhaps lower), said Zach Allen, head of Pan EurAsian Enterprises, a management advisory firm that follows LNG markets.
That’s a price the U.S. hasn’t seen since 2002. “Some cash is better than none, especially for producers who rely heavily on that cash for social and other programs that would be politically explosive to cut off or cut back,” Allen said.
The biggest contributors to the world LNG market is Qatar, followed closely by Indonesia. The productive capacity of the gas wells in these countries dwarf domestic production, and new liquification-export facilities that have activated in recent years, and more that will be coming-on-line in the coming months, will only add to the world’s ability to produce LNG.
What’s more, most of these big, foreign wells have zero or near-zero cost of gas production, because they produce liquids in volumes sufficient to pay for the cost of finding and developing the wells. So they are essentially producing gas for free.
Even more encouraging for foreign LNG producers is the discovery of new super-giant, and world-class giant gas production zones. Overshadowing them all, is InterOil’s (IOC) recent new discovery in New Guinea, the Antelope 1 well, which likely contains ten trillion cubic feet. One well, ten TCF. Just put a liquification plant near-by and that well could supply the gas needs of several countries for many years.
Even without any of the additional supply from these new fields, the new production coming on line in Qatar is more than the current market can absorb, and the Qatar CEO notes , “For the shorter term, I don’t think the UK will be able to take 16 million tons,” al-Suwaidi said. “Anything the UK cannot absorb, we will have to find a market for.”
The consumption of petroleum products in Japan, the world’s biggest buyer of LNG, is projected to fall 4.7 per cent in the year starting this month, according to the Institute of Energy Economics Japan. The global recession has reduced electricity use in Japan. Barclays Capital said the global LNG market will add 5.6 BCF/d of production capacity to the 23 BCF/d currently online.
Current U.S. LNG gasification-import capacity is about 60 million tons per year, and several new LNG receiving terminals are coming into operation in 2009, including Sabine Pass in Louisiana. (One metric ton is equivalent to about 48,700 cubic feet of NG). One LNG tanker can transport 6 billion cubic feet of gas–which is equivalent to estimated recovery over the lifetime of a decent shale well.
While the EIA estimates LNG imports to average about 369 BCF, estimates vary widely. “We are going to be awash in natural gas and could have $2 gas”, says Steve Johnson, president of Houston-based Waterborne Energy Inc., which tracks LNG shipments. He also predicts that the US will see 1.1 TCF of gas delivered to the US in 2009 as repairs to some LNG export facilities overseas are completed, new projects come online and seasonal shifts in global demand increase the amount of LNG in the market.
LNG: there’s plenty of it, just like there’s plenty of Shale. The difference is that no matter how cheap it gets to produce Shale gas, LNG will always be cheaper–it costs nothing to produce so the only cost is transport. And that transport cost is only between $1.29 to $2.09 from the Middle East to various U.S. import facilities. Its doubtful that Shale producers could be profitable at those levels.
With so much cheap LNG in the world, gas prices in the coming years may not be based on futures at all, Henry Hub could be a thing of the past, and U.S. traders might just be buying and selling gas based on spot LNG prices.
Demand Side
“Demand destruction will still outpace supply destruction through this summer and into next winter," Stephen Schork, president of the Schork Group Inc., an energy markets consulting company in Villanova, Pennsylvania, said in a note on April 24th. Businesses are closing, and unemployment continues to rise, which means big trouble for natural gas prices.
NG is a major power source for electrical utilities, and it has been building up in storage at levels well above seasonal averages as manufacturers cut back on production. The EIA reported Thursday that natural gas in U.S. storage is now 36 percent greater than it was at this time last year. On Friday, American Electric Power said that electricity use by industrial customers in its region fell 15 percent. That falling demand can also be seen clearly in recent unemployment figures, with energy intense industries like manufacturing hit particularly hard.
Earlier this year, Dow Chemical (DOW), which had previously been one of the largest single consumers of NG in the country, closed 20 plants and cut 5000 jobs since December. The three major U.S. automakers have slowed down production this year to match a plunge in demand. General Motors (GM) said Thursday it would shutter 13 assembly plants for up to 11 weeks this summer. Ford Motor Co. (F) also has cut back on manufacturing this year.
In addressing the demand for natural gas this year and in the coming years, we must acknowledge that demand for natural gas is a reflection of aggregate demand in the greater American economy, and therefore the global economy. Because manufacturing and fertilizers make up such a large portion of the demand picture for NG, it is unlikely that such demand will increase to levels seen in recent years as long as the overall economy remains on its current deflation-depression path.
So, deflationary forces retrench across the world economy, even in the face of unprecedented low interest rates and quantitative easing by central banks, and demand for NG stays weak.
Where has growth come from, anyway, in the last ten years - other than by an expansion of the money supply and credit? The fate of NG prices is just a manifestation of the credit-bubble blow-back.
A look at almost all other asset classes shows them returning to 1997-1998 levels, adjusted for inflation. The S&P 500, at present writing, is at about 1998 levels, and real estate, though widely varied across the country, is at about 2002 levels and continues to fall as new-buyers shy away and inventories of unsold houses stagnate. If most of the economic growth in the last ten years has been a product of the great asset and credit bubble, and all asset classes are deflating down to values last seen ten years ago, then why shouldn’t NG prices go back to 1997-1998 levels?
As we mentioned above, the cost of getting the LNG from its foreign origin to other markets is low. The 43-day round trip from the huge export terminal in Qatar to the Lake Charles LNG terminal costs $2.09 per million British thermal units. From Egypt to Lake Charles takes 30 days and $1.29 per million Btu. $1.29 to $2.09?
Funny, that’s precisely where gas prices were in 1997, 1998. The grip of deflation is firmly in place. Go down, Moses, and take NG prices with you. So, prices will revert to the mean and crash through it, right back to the late ’90s levels–which is where prices should be (after all) at a more honest time (perhaps), before the bubble took hold.
If we are going back to 1998 levels, then it looks like we can take several TCF off the table, which suggests that only the largest, most prolific, and most efficient domestic gas plays will be workable.
Without the drawing of a new source of domestic demand for NG, domestic marginal producers can fuggedaboutit. LNG will punish them. Still, the prospect of low natural gas prices persisting well into future makes NG attractive as a fuel for electricity generation and transportation.
I don’t know, but anyone in the power world out there please chime in, if you are operating a power plant at dual capability, at what point do you switch to NG from coal? $2.50? Please chime in and comment here, coal people. That may give a glimmer of hope to those in the NG business.
But no hope can be found in the Obama administration, which scorns all associated with the O&G business, so it's not likely that NG will get much support from government “stimulus” efforts of from Department of Energy policy. Even if we were to actually see a proliferation of new usage of gas as the product of government mandates or incentives, any marked increase in the actual amount of gas consumed from those hypothetical projects would still be years off. And it's doubtful that many domestic producers can weather such a long stretch of very low prices.
Disclosure: no positions
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This article has 41 comments:
Great Article. Very thorough.
Thank you for the hard work. I have printed and saved it for future reference.
Jim Pearson
Pearson & Pearson
Commercial Litigators
P.S. I think I will sell my UNG.
Another thing you didn't note: a huge percentage of the LNG from Qatar is obligated to go to the US. It can be re-routed to Europe or other places if the price is higher and the demand is there. But if there is no demand in Europe, that LNG HAS TO COME TO THE U.S. There it will be pushed into the pipelines, backing out domestic production and keeping prices way down for at least a year. The savoir here: demand pick up...which will only happen after we get this recession off of our backs!
Putin Hails End of 'Cheap Gas' Era
www.spiegel.de/interna...
On Apr 27 09:36 AM desoto Dude wrote:
> Good info on transportation cost of LNG. Gas may be "free" at well
> head, but somebody has to pay to liquefy and regasify, plus at least
> 15% for mrketing and administration. Landed US cost of $4 to $5 with
> zero profit.
But that was some time ago. Today I prefer to believe that the price of gas will end up much higher than anything suggested in this article, and I definitely don't have the faith in shale gas that this author does: the natural depletion is too high. I'm not particularly optimistic about LNG either, but I have other things to worry about: if Mr Putin says that the gas price is going to go up, he might be able to make it happen, and the moronic Swedish government wants gas to replace nuclear..
However, I like this article. It's not easy not to make mistakes about gas with the demand side of the market like it is today.
On Apr 27 10:31 AM Stone Fox Capital wrote:
> good info. The one thing I wonder about demand is that most utilities
> still haven't passed the lower cost down to consumers. Most locked
> in prices at the much higher rates. Getting gas prices down to the
> current market rates this winter could help increase demand.
$2.09 + $2 + $.50 + 15%=A lot more than $2
Is Qatar gas "obligated" to US? Under long term contracts? I have read that US regasification plants running at less than 50% capacity? Are they obligated to take Qatar gas? If not, who?
I am really trying to learn here. There seems to be a lot of conflicting information on LNG.
Thanks!
On Apr 27 09:35 AM Mmarrkk wrote:
> You are one of the few folks who "get" the real price of imported
> LNG! LNG is dirt cheap once the facilities and ships have been built.
> Those are sunk costs and the operators of the liquifaction plants
> just want to keep them running and eek out a very small OPERATING
> PROFIT. Yeah, it makes the several billion dollar investment a poor
> one, but it would be worse if you shut down the plant completely!
>
>
> Another thing you didn't note: a huge percentage of the LNG from
> Qatar is obligated to go to the US. It can be re-routed to Europe
> or other places if the price is higher and the demand is there.
> But if there is no demand in Europe, that LNG HAS TO COME TO THE
> U.S. There it will be pushed into the pipelines, backing out domestic
> production and keeping prices way down for at least a year. The
> savoir here: demand pick up...which will only happen after we get
> this recession off of our backs!
I think the number CS is showing is not an incremental cost to liquify; Total all in costs are about $2.50/3.00 in to the U.S. pipeline (liquify, ship, regas). 15% marketing/admin is way too high!
On Apr 27 01:13 PM keithfeather wrote:
> NG cheaper than coal? Not likely. Delivered coal at $3.00/mm btu
> generally keeps NG above that floor, as switching is possible.
On Apr 27 12:29 PM Mmarrkk wrote:
> A large portion of the Qatar LNG has to go to the US receiving plants.
> They do have re-route rights if they can get a better price, but
> in the end, if no other home for the gas, the US plants HAVE to take
> it.
>
> I think the number CS is showing is not an incremental cost to liquify;
> Total all in costs are about $2.50/3.00 in to the U.S. pipeline (liquify,
> ship, regas). 15% marketing/admin is way too high!
Your numbers on LNG transport costs are reasonable, but there are a few reasons I think you are shorting an exhausted bear market. It's all about volumes at the margin...
A few basics...
North American demand is ~25 TCF a year. We've used over 1 Quadrillion cubic feet of natural gas since WW2, and recession or not gas use is entrenched in this econcomy.
Industrial demand is about 30% of that, and if it's off 50% that's only 2.5 TCF a year. Power, electricity and heating usage numbers don't correlate to price, and demand in those areas is not dropping.
If you forecast 1.1 TCF a year in LNG you are suggesting that 4% of a normal market can be supplied by LNG, at the port. You haven't assumed any cost to transport gas from LNG terminal to end user, but lets call that a given.
Conventional gas production still makes up the vast majority of North American Production, approximately 20 TCF year. This gas has a marginal cost of $8.50 per MCF, and a decline rate of ~30% annually. If the price isn't $8.50 reinvestment drops, and this wedge of gas declines to 14 TCF in a year and 10 TCF in two year. Already we have just lost more than 10 times the LNG market you predict... so much for 4% of the supply setting the price!
Shale gas was forecast to triple in productivity to 18 BCF a day or 7 TCF a year over the course of the next 3 years, though current drilling rates will not accomplish that. Declines in shale wells are HUGE, up to 60% in the first year. Shale gas facilities are engineering nightmares unless drilling is constant. Compression ratios go out of whack, and base load of the compressors becomes a serious issue. You've got to have gas to compress gas otherwise compressors don't work.
What is likely to occur is a series of fractionated markets... this is largely due to the inadequate pipeline infrastructure between markets. There is only so much gas that can travel from Texas to NYC, and other area of use. If gas can't make it out of an area, the area price drops.
Shale players and LNG in Texas are in for a big headache, but the market as a whole is destined to rise again, and soon. Gas costs money to move on land... compression is not cheap, and pipeline tariffs can be as high as $1.44 per mcf (believe me I own pipelines, as well as gas wells.)
Differentials will be greatest in markets that have LNG terminals & shale gas like Texas, while other regions will see higher prices. This exact situation exists in the Rockies region and has since the discovery of the giant Pinedale field. You may remember that gas traded down to $0.07 per mcf in Pinedale a few years ago, and that was during the boom.
Prices will not be sustained at the levels you predict as the costs of supply are nearly an order of magnitude higher than in 1997-1998 time periods. Royalties go up as people hear about the "Big finds" and service companies charge more and more for the same work as plays become more well known.
Select operators, in the right areas will be able to profitably produce gas at $6 in the big shale plays, but the market is headed back to $8 to offset the major declines coming in conventional production.
It may be a bumpy ride along the way, but the traders in NYC seem to only know the "storage" trade. That's only a part of the supply/demand picture and is really irrelevant when the entire cost structure is examined. Once injection numbers start to disappoint the guys on the floor watch out, the bear market's over.
cheniere is a stock i wouldn't touch in this environment
On Apr 27 03:52 PM Amouna wrote:
> A good play for this would be long Cheniere Energy (seekingalpha.com/symbo...).
> Their stock will take off to the moon in a matter of months....
The point is: there will be U:S. companies forced to produce a lot of NG even at $3 NG or below. But there are a lot who are not and who will not sell their Ng below 4$. They will simply produce as much as they need to keep their lights on and will wait for prices to improve rather than virtually give away their NG reserves. And rest assured, the administration in DC will not sit idle watching the destruction of the U.S. natgas industry which forms a center piece of their future energy policy. Expect nothing less than significant tariffs for LNG imports.
I have no idea where Ng prices will be a year or two from now. But my bet (and my money) is with strong low-cost producers like mcf and chk. CVHL's chairman over the past years has been pretty good in judging the market and he has hedged the company accordingly.. he has been cautious on NG, too and not ruled out price weekness to last well into 2010.
Still, at 3-3.50$ a lot of production will simply go off the market, so i simply don't see it to fall much lower from here. it may rise back into the $4-$6 range gradually as the low prices attract additional demand and additional uses.
sorry for the typo
On Apr 28 05:41 AM User 305589 wrote:
> good article. However, the market has been looking at this for the
> past 6 months or so - the current depressed NG prices are depressed
> precisely because of these bearish factors. While oil has risen 50%
> off its lows, NG is making fresh lows, defying the long established
> crude-ng price relationship.
> The point is: there will be U:S. companies forced to produce a lot
> of NG even at $3 NG or below. But there are a lot who are not and
> who will not sell their Ng below 4$. They will simply produce as
> much as they need to keep their lights on and will wait for prices
> to improve rather than virtually give away their NG reserves. And
> rest assured, the administration in DC will not sit idle watching
> the destruction of the U.S. natgas industry which forms a center
> piece of their future energy policy. Expect nothing less than significant
> tariffs for LNG imports.
> I have no idea where Ng prices will be a year or two from now. But
> my bet (and my money) is with strong low-cost producers like mcf
> and chk. CVHL's chairman over the past years has been pretty good
> in judging the market and he has hedged the company accordingly..
> he has been cautious on NG, too and not ruled out price weekness
> to last well into 2010.
> Still, at 3-3.50$ a lot of production will simply go off the market,
> so i simply don't see it to fall much lower from here. it may rise
> back into the $4-$6 range gradually as the low prices attract additional
> demand and additional uses.
On Apr 28 12:42 AM RJB 1077 wrote:
> Not quite.
>
> Your numbers on LNG transport costs are reasonable, but there are
> a few reasons I think you are shorting an exhausted bear market.
> It's all about volumes at the margin...
>
> A few basics...
>
> North American demand is ~25 TCF a year. We've used over 1 Quadrillion
> cubic feet of natural gas since WW2, and recession or not gas use
> is entrenched in this econcomy.
>
> Industrial demand is about 30% of that, and if it's off 50% that's
> only 2.5 TCF a year. Power, electricity and heating usage numbers
> don't correlate to price, and demand in those areas is not dropping.
>
>
> If you forecast 1.1 TCF a year in LNG you are suggesting that 4%
> of a normal market can be supplied by LNG, at the port. You haven't
> assumed any cost to transport gas from LNG terminal to end user,
> but lets call that a given.
>
> Conventional gas production still makes up the vast majority of North
> American Production, approximately 20 TCF year. This gas has a marginal
> cost of $8.50 per MCF, and a decline rate of ~30% annually. If the
> price isn't $8.50 reinvestment drops, and this wedge of gas declines
> to 14 TCF in a year and 10 TCF in two year. Already we have just
> lost more than 10 times the LNG market you predict... so much for
> 4% of the supply setting the price!
>
> Shale gas was forecast to triple in productivity to 18 BCF a day
> or 7 TCF a year over the course of the next 3 years, though current
> drilling rates will not accomplish that. Declines in shale wells
> are HUGE, up to 60% in the first year. Shale gas facilities are engineering
> nightmares unless drilling is constant. Compression ratios go out
> of whack, and base load of the compressors becomes a serious issue.
> You've got to have gas to compress gas otherwise compressors don't
> work.
>
> What is likely to occur is a series of fractionated markets... this
> is largely due to the inadequate pipeline infrastructure between
> markets. There is only so much gas that can travel from Texas to
> NYC, and other area of use. If gas can't make it out of an area,
> the area price drops.
>
> Shale players and LNG in Texas are in for a big headache, but the
> market as a whole is destined to rise again, and soon. Gas costs
> money to move on land... compression is not cheap, and pipeline tariffs
> can be as high as $1.44 per mcf (believe me I own pipelines, as well
> as gas wells.)
>
> Differentials will be greatest in markets that have LNG terminals
> & shale gas like Texas, while other regions will see higher prices.
> This exact situation exists in the Rockies region and has since the
> discovery of the giant Pinedale field. You may remember that gas
> traded down to $0.07 per mcf in Pinedale a few years ago, and that
> was during the boom.
>
> Prices will not be sustained at the levels you predict as the costs
> of supply are nearly an order of magnitude higher than in 1997-1998
> time periods. Royalties go up as people hear about the "Big finds"
> and service companies charge more and more for the same work as plays
> become more well known.
>
> Select operators, in the right areas will be able to profitably produce
> gas at $6 in the big shale plays, but the market is headed back to
> $8 to offset the major declines coming in conventional production.
>
>
> It may be a bumpy ride along the way, but the traders in NYC seem
> to only know the "storage" trade. That's only a part of the supply/demand
> picture and is really irrelevant when the entire cost structure is
> examined. Once injection numbers start to disappoint the guys on
> the floor watch out, the bear market's over.
I say it is becoming closer as in the past, when layoffs did occur they were predominantly in the MFG sector. As America becomes more of a service based economy, when lay offs do occur, its office space that is emptied, not MFG.
Staying with that thought, average watts per square foot MFG 15, AWPF office space 1.7. With that said, do you think this will effect the electrical demand and create an offset that is anticipated?
Thanks,
Now it looks like the woodshed might become my second home?! Uncle, uncle, uncle. I cant take much more.
Consumption doesn't go down commensurate with reduced economic activity though it may go down somewhat with the economy down. Are you all shutting off your VCR and cable box at night (for instance)? I'm not.
Yes the essence of my comment is that gas is a constantly declining product. And continuous reinvestment via drilling is required simply to keep supply from dropping like a rock through the demand curve.
That process has already begun, and is irreversable without a rise in prices. As for your question, there isn't a level where LNG would ever set the low marginal cost, as there just isn't enough of it available. Even if industrial demand goes to zero, LNG is not available in quantities enough to offset the decline.
LNG has the ability to set the high margin, but the low price will be set by conventional, and then unconventional land based supply.
Price will rise in 2009.
Remember we can jam 4 TCF into storage, which is only 16% of a normal years usage... that leaves 84% of the supply/demand equation that the storage picture can't speak to.
It's all about supply destruction, and demand destruction... prices can'd drop any further or supply will artificially drop below demand as people turn gas wells off instead of selling at a loss at the wellhead.
I appreciate this discussion is about LNG, but I think you are looking for an answer that will be found elsewhere. LNG doesn't have as much impact as you write about in your article.
Cheers,
Roger
On Apr 28 07:31 AM Buck East wrote:
> RJB-thank you for the comment and great analysis. Your point (and
> others') about conventional supply shut-in is salient and appreciated.
> However, LNG import capacity is increasing in this country and also
> in Mexico, which is the backdoor to the U.S. Market. Am I right in
> saying that at the heart of your position is the idea that supply
> will drop off worse than demand? I suppose this is the core of the
> debate, and I agree that those who trade on "storage" may be bias
> toward demand and blind to projecting production numbers further
> in the future. Decline in demand, as manifested by less NG uses in
> electricity and manufacturing, may have only begun to show itself--would
> your analysis change if we had Dow at 5500 and 20% real unemployment?
> What amount of LNG imports, in your opinion, would keep prices sub
> $3? sub $4?
We live in a real interesting time in our lives, I can only imagine what the next 6 months are going to bring.
On Apr 28 01:02 PM Buck East wrote:
> Cobra 1, very good point--manufacturers, e.g. chemicals, use NG in
> their processes as well as use alot of electricity so the negative
> impact in demand is doubly harsh. Your point re net gain/or loss
> with electricity usage going more toward houses and apartments rather
> than offices: I wish I knew and it will be interesting to see and
> please send me some data on that if you find any in coming months.
> From a social perspective re unemployment and all--I would bet that
> more unemployment would not end up netting more electrical use because
> I'm guessing that people staying home because of no job means no
> income and that they would do everything they could to save on those
> odious monthly bills--adjust thermostat, turn off appliances etc.
> In a continued high-unemployment scenario, more people will be moving
> in with roomates, parents, other family as well which will result
> in more vacant housing and a net savings of electricity. (Maybe people
> will even be driving less as a result of unemployment even at $2-$3
> gasoline, not directly related to NG I know, but my poiny is that
> its important to look at NG demand in broad context).
Also, what about LNG demand potential for China and India. Is that relevant at all in the short or intermediate term?
Finally, what about NG as a substitute for gasoline? Too far fetched? Seems very economic as an alternative.
Think. Use your noodle.
seekingalpha.com/artic...
shareholdersunite.com/.../
Nice work, but there are many things that I think you simplified too much. Shale plays like the Barnett, Marcellus, etc. are not all just sure bets - drill a horizontal hole and produce. Sure, much progress has been made with horizontal drilling and frac techniques. But, some areas of Barnett are great - some not so great. Marcellus is too new to know how prolific it will be - but it is not as simple a program as the estimates will have you believe. Some of the Marcellus is highly fractured while other areas are much tighter. You'd think fractured would be good, but early results (not published) have suggested otherwise.
Another problem with shale plays is that they do indeed deplete at a much faster rate than the old traditional deep or tight gas plays. A few years ago, first year deplection rates were in the teens. Now, with so much shale production, 1st year depletion rates have been estimated to be in the mid-30's. So, if the drilling rig fleet drops from 1700 to less than 1000, the depletion rate will effect production much more than in the past.
You also make a good point about lower prices forcing out the marginal producers. One of the reasons that the rig count was so high was because of the high rates. Every geologist and his friend suddenly decided to drill a well. Heck, 3 guys on my block were drilling personal wells as recently as 6 months ago. One is still going at it today.
You are correct, many wells have been shut in and can be brought back on. Usually this is not a simple valve opening exercise. The wells that some workover effort to get things up and going. And, you can bet with the low prices, producers will take a long look at the market outlook before they make the effort to open up the spigot. Will LNG really be able to make a big difference once supply/demand come back in balance? Maybe, but when prices were high a year back, the US actually imported less LNG than the previous year because the other markets were willing to pay more than the high US rate.
Again, nice analysis, but I think there are a number of moving parts in this puzzle that don't make it out to be as simple as it sounds. You've probably guessed by now, but I've place my bets that the price is going up. For disclosure purposes, I hold CHK, APA, UPL, APC, XTO, EOG, DNR, DVN.
What is maximum LNG storage or terminal capacity for the U.S.
currently? I believe I have seen 1.7 TCF. Do you agree with the
Energy Information Agency estimate of a 1.2% drop for natural gas production in 2009? Given the rig count drop and depeltion rate, that number seems "light".
On Apr 28 12:42 AM RJB 1077 wrote:
> Not quite.
>
> Your numbers on LNG transport costs are reasonable, but there are
> a few reasons I think you are shorting an exhausted bear market.
> It's all about volumes at the margin...
>
> A few basics...
>
> North American demand is ~25 TCF a year. We've used over 1 Quadrillion
> cubic feet of natural gas since WW2, and recession or not gas use
> is entrenched in this econcomy.
>
> Industrial demand is about 30% of that, and if it's off 50% that's
> only 2.5 TCF a year. Power, electricity and heating usage numbers
> don't correlate to price, and demand in those areas is not dropping.
>
>
> If you forecast 1.1 TCF a year in LNG you are suggesting that 4%
> of a normal market can be supplied by LNG, at the port. You haven't
> assumed any cost to transport gas from LNG terminal to end user,
> but lets call that a given.
>
> Conventional gas production still makes up the vast majority of North
> American Production, approximately 20 TCF year. This gas has a marginal
> cost of $8.50 per MCF, and a decline rate of ~30% annually. If the
> price isn't $8.50 reinvestment drops, and this wedge of gas declines
> to 14 TCF in a year and 10 TCF in two year. Already we have just
> lost more than 10 times the LNG market you predict... so much for
> 4% of the supply setting the price!
>
> Shale gas was forecast to triple in productivity to 18 BCF a day
> or 7 TCF a year over the course of the next 3 years, though current
> drilling rates will not accomplish that. Declines in shale wells
> are HUGE, up to 60% in the first year. Shale gas facilities are engineering
> nightmares unless drilling is constant. Compression ratios go out
> of whack, and base load of the compressors becomes a serious issue.
> You've got to have gas to compress gas otherwise compressors don't
> work.
>
> What is likely to occur is a series of fractionated markets... this
> is largely due to the inadequate pipeline infrastructure between
> markets. There is only so much gas that can travel from Texas to
> NYC, and other area of use. If gas can't make it out of an area,
> the area price drops.
>
> Shale players and LNG in Texas are in for a big headache, but the
> market as a whole is destined to rise again, and soon. Gas costs
> money to move on land... compression is not cheap, and pipeline tariffs
> can be as high as $1.44 per mcf (believe me I own pipelines, as well
> as gas wells.)
>
> Differentials will be greatest in markets that have LNG terminals
> & shale gas like Texas, while other regions will see higher prices.
> This exact situation exists in the Rockies region and has since the
> discovery of the giant Pinedale field. You may remember that gas
> traded down to $0.07 per mcf in Pinedale a few years ago, and that
> was during the boom.
>
> Prices will not be sustained at the levels you predict as the costs
> of supply are nearly an order of magnitude higher than in 1997-1998
> time periods. Royalties go up as people hear about the "Big finds"
> and service companies charge more and more for the same work as plays
> become more well known.
>
> Select operators, in the right areas will be able to profitably produce
> gas at $6 in the big shale plays, but the market is headed back to
> $8 to offset the major declines coming in conventional production.
>
>
> It may be a bumpy ride along the way, but the traders in NYC seem
> to only know the "storage" trade. That's only a part of the supply/demand
> picture and is really irrelevant when the entire cost structure is
> examined. Once injection numbers start to disappoint the guys on
> the floor watch out, the bear market's over.
I would imagine that all it would take for shorts to start scrambling is a whiff of a cat IV or V hurrican brewing off the coast, gov legislation in cap and trade, weaker injection numbers...etc.
The short side of this trade seems a bit too crowded at this point.
As I've been trying to learn about this and other things, I have been wondering if the LNG import is as much of a threat as we might believe. The cause for this is the lack of strength for the U.S. dollar.
Since early April, we've had a drop of 8.5% in the dollar index ($86.87 -> $79.13 and it was even higher in early March at $89.51). My thinking was that with ZIRP and QE and BHO/Pelosi policies taking control, along with all the other stuff in the economy we know of, that the dollar would continue to weaken.
If I combine this with an expected recovery in emerging markets (BRIC, etc.), and BRIC countries now writing contracts in currencies that bypass the U. S. $, I have begun to think that LNG demand in places outside the U.S. might absorb the expected LNG increases *and* any market other than the U.S. would be preferable due to the relative currency strengths. That is, why should I sell to a weak-demand market with a weak currency when I may be able to sell to strong-demand countries with relatively stronger currencies.
Is this a valid concern? I've been thinking we wouldn't see much LNG import because of this.
Thanks,
HardToLove
www.cleanenergyfuels.c...