You may find this of interest looking forward ...Please note...

You may find this of interest looking forward ...

Please note copying or reproduction of this article is strictly prohibited without the written permission of the writer. The views contained within it are my own.

I intend to update this article every 3 to 6 months, however I will be issuing a further supplementary paper before the end of January 2012.

US economy receives a hidden stimulus of $440 Billion since August 2008, including a record (thus far) $16.5 Billion in December 2011, which has driven growth in the US economy, unseen in any of the other G20 economy’s at this time. This economic stimulus will continue and increase in value for some time to come, I currently project that it will exceed $610 Billion by the end of 2012.

Many economists and financial commentators have become overly fixed on the Obama administration & Congress (both the House of Representatives and the Senate) over the payroll tax cut, in the last few weeks.

Yet I have seen little, if any commentary on the major effects the USA Natural Gas market is having throughout the USA and the economy.

Trends & Thoughts on the USA Natural Gas Market as at 1st January 2012.

I am simply a small overseas private investor and I hope this entire thesis relating to the USA Natural Gas market will help others to understand some major factors that I believe are at work, which are allowing the USA to grow when Europe and other Country’s are in or heading towards recession.

In early August 2011 Natural Gas in storage in the USA was some 200 Billion Cubic Feet (BCF) below that in storage in 2010 and 80 BCF less than the 5 year rolling average. Since then the storage of Natural Gas has rocketed and now in late December 2011 Natural Gas in storage is some 300 BCF above last year’s level and 425 BCF above the 5 year rolling average. A remarkable 500 BCF turnaround in under 5 month’s, thanks to shale gas & shale oil.

The number of working Natural Gas drilling rigs in the USA is at decade low’s and still falling and the price of Natural Gas is just over $3 per million cubic feet (MCF) and is likely to fall much further over the first half of 2012. Indeed if the next 12 weeks (to end of March 2012) do not contain a considerable period of severe cold weather, then by the end of April 2012, I predict Natural Gas in storage could be 1 Trillion Cubic Feet (TCF) above the 5-year average (at close to 2.5TCF rather than 1.5TCF) and consequently the price of Natural Gas will plummet and easily trade below $2.25 per MCF possibly going below $2 per MCF during the 2nd quarter of 2012.

How does this tie into US growth & competitive advantage I hear you ask? Well let me explain further.

Anywhere else around the developed world you are looking at something like $9+ per MCF for Natural Gas and in some Country’s it cost’s up to $16 per MCF. So USA heating bills and electricity prices are much lower than they otherwise would be in other Country’s around the world thanks to Natural Gas.

The USA consumes about 60 BCF of Natural Gas per day on an annualised basis (with large peaks in winter for heating & small peaks in summer through electrical consumption of air conditioners) as well as close to 19 million barrels of crude oil.

Only a few years ago it looked like the USA was going to run out of Natural Gas in the not too distant future but thanks to horizontal drilling and advances in extraction techniques (fraccing) in shale gas and shale oil formations, the USA now has enough domestic supplies to easily last 100 years or more.

This is great news for the USA as it was starting to look at significant liquefied Natural Gas (LNG) imports from around the world as soon as 2015 to make up the shortfall between production and consumption, until this happened.

However all this shale gas and shale oil comes at a cost, horizontal drilling is not that cheap and neither is the cost of fraccing the shale to enhance oil, gas and condensate (liquid natural gas) production rates.

Every USA shale formation is different, some are very oil prone, others Natural Gas prone and some like the Eagleford Shale in Texas vary within themselves having a dry gas zone, a liquids rich zone and an oil zone.

Most USA focussed oil and gas company’s believe they need a price of around $7 per MCF to break-even on purely shale gas formations (or sometimes called dry gas zones), let alone make a profit.

Historic lease costs

You need to go back in time to around the 2006-2009 period, to understand the main reason’s behind the cost structure. It was during this time that oil and gas production from shale fields started to really take off.

The Barnett shale in Texas was where the first real experiments in fraccing techniques were undertaken (2002-2005), some worked others didn’t, company’s fine tuned them, changed them, refined them again and again to get more consistent results. At this point the smart movers (first movers) started to lease other previously known about shale formations like the Haynesville and Marcellus shale’s. The cost of leasing to these first movers was in the low $100’s per acre.

As well’s were drilled in these formations and results became known, hot spots (good producing parts) appeared. Some of the wells had fantastic results and this attracted the interest of large players, who started to lease large area’s themselves. However as competition grew, so did the price of leases as the shale formations while vast, still only cover a certain amount of ground. Lease prices were soon into the low $1000’s per acre. As time passed and it became apparent from the drilling results that some area’s within the formation were much better than other’s. The big players then wanted the good productive leases (second movers) in their portfolios.

At the exact same time prices for Natural Gas in the USA were on the rise, from 1994 to 2000 the price was between $2-$4 per MCF, then in 2001 it spiked briefly to over $9 before falling back into the old price range during 2002. In 2003 it was in the $4-7 range, in 2004-05 it was in the $5-8 range, until the Aug -Sept Hurricane’s of 2005 caused it move sharply high to peak at over $15 before year’s end. During 2006-07 prices were a constant $6-8. In 2008 they spiked again to reach over $13, even in the midst of the financial crisis and didn’t fall below $6 again until 2009. Since then they haven’t got above $6 and have been briefly below $3.

The financial crisis hadn’t really had an effect as yet and the high natural gas prices, tight supply, high production rates in the good area’s, caused the bidders to make massive offers to buy into the good leases, with many leases going for over $10,000 an acre and prices peaked around $25,000 an acre in the Haynesville shale. Billion’s of dollars were spent buying up these leases.

Then the bottom started to fall out of the market, in part due to the financial crisis. To start with the company’s shielded themselves from the worst of the falls by hedging forward a certain amount of their production for 2009 and 2010 at prices of $9 and $7 per MCF. The amount of production hedged, fell with each passing year thus increasing the company’s losses as Natural Gas prices failed to recover.

By 2010 it had reached the point where company’s were left with 2 bleak choice’s drill or lose your leases, they chose to drill and absorb the losses.

It was during 2009 that shale oil rather than shale gas started to increase in prominence thanks to the Bakken shale in North Dakota and the Eagleford Shale in Texas. The use of fraccing techniques in these shales (by first movers), allowed oil to be produced from them, at commercially viable rates (thanks to low lease cost and acceptable oil prices $75+). Within a year further significant advances in fraccing techniques meant that wells in the Bakken shale for example were suddenly producing at least twice as much oil as before (in many cases initial flow rates were up to 5 times that achieved by the early horizontal wells).

In 2010 the Eagleford shale had become much more defined, company’s knew which leases fell into the dry gas zone, which were in the wet gas zone and those in the oil zone. The big players started to move in, seeking out the most productive area’s of the wet zone and oil zone and bidding for leases accordingly, just as had happened in the Haynesville, the likes of Petrohawk one of the first involved in the play had only paid a couple of hundred dollars an acre for its position in 2009, those buying in, in late 2010 now were having to pay top dollar $4,000+ an acre for new leases, with some small company’s being bought out for over $15,000 an acre as they had prime leases with some production history. In late 2011 Eagleford leases in the good area’s are being bought for around $20,000 an acre. The big players will have spent ten’s of billions of dollars simply buying Eagleford leases or whole company’s (like BHP’s purchase of Petrohawk for $12 Billion), let alone the cost of drilling & fraccing them. To drill and frac a single well with a 4000ft horizontal lateral, which is enough to drain an area of 80 acres you won’t get much change from $7M.

Other oil or liquid rich shale plays that started to come to prominence in 2011 include the Permian basin in Texas, Niobrara in Colorado and the Mississippian play in Oklahoma/Kansas.

The Eagleford, Permian & Mississippian plays have really good gas gathering systems around them. In almost all the wells in these area’s, some natural gas production comes alongside the oil and/or condensate production and is being captured and sold. The cost of doing so is not that high, so it provides an additional revenue stream with the natural gas in effect being sold as a by-product.

In the Bakken there is little natural gas infrastructure in place so most natural gas is simply flared, for now.

These oil/liquid rich shale formations have helped USA oil production stop its yearly decline and are now causing USA domestic production to rise once more, from 5.2 million barrels a day in July-August 2009 to over 5.8 million barrels a day in December 2011. It will soon top the 6 million mark. That’s an increase of over 15%. Bakken oil production alone has increased by 40% or 100,000 barrels of oil a day in the first eight months of 2011 (from 230,000 to 330,000 bod).

Oil prices are set international, whereas Natural Gas prices are set domestically, so the savings are different, however the increase in USA domestic oil production is helping the USA balance of payments by cutting down the amount of oil imports required each month. The current 0.6+ million barrels of oil a day increase, works out around $60M a day in savings or a $1.8 billion a month benefit to the USA balance of payments.

The USA consumer makes up about 70% of the economy, so the amount of discretional spending they have is key to the health of the USA economy and its economic growth.

Lets assume for a minute a constant Natural Gas price of $6 per MCF rather than the current $3 per MCF, at that price USA consumers and companies would need to find an extra $180M a day or an extra $5 Billion a month, simply to heat their homes with natural gas or cover the expected rise in electricity prices (created from increased input cost for electricity generators).

The rise in energy prices would cause many USA companies to increase the price of their finished goods, making them less competitive around the world and at home. Hurting exports, increasing imports and causing inflation to rise. It would also most likely lead to higher unemployment as well due to the loss of Industrial competitiveness.

For the moment this is not the case and the natural gas market is currently a “loss leader” (in supermarket terms) allowing all this, what I would call additional money ($2.5 billion a month for households) to be spent on other goods and services. As well as the ripple effects this direct spending has throughout the economy. It is this turnaround that has driven USA growth in the second half of 2011 more than any other.

The key to the future will be the major oil and gas companies and sovereign wealth funds, their “loss leader” will not last forever. At some point in the not to distant future they will say enough is enough and try to change the Natural Gas market dynamics completely.

The trigger event for this turnaround could be one of several.

A sharp fall in the Natural Gas price due to a mild winter, leaving plenty of gas in the storage facilities, (most likely scenario).

A number of the Natural Gas focussed producers, who have very little oil production being forced into Chapter 11 or seeking mergers, as they are continually drained of cash month after month.

The large oil & gas company’s reaching the point where all their key leases are held by production for years to come and suddenly they are back in control rather than being forced to suffer the least of 2 evils (lose your leases by not drilling them thus forgoing millions spent in lease purchase costs or drilling the wells and suffering more losses which are not fully recovered from production revenue but allow you to retain your leases)

A sharply falling oil price would make the by products of Natural Gas Liquids (NGL) and Natural Gas more significant to the economic viability of some wells, However I can’t see any real weakness occurring in the oil price during 2012

Moratorium on the fraccing of shale formations in certain area’s due to possible contamination issues or other as yet unknown issues associated with the process. A topic investors should monitor closely.

So who are the big players in these shale plays, well you’d be surprised, yes Exxon of course, Chesapeake, Chevron, then some international ones like Reliance of India, BHP Billiton, CNOOC of China, PetroChina, BP, Shell, Total, Once one big player makes it clear that they are cutting back natural gas production dramatically, the rest will no-doubt quickly follow suit.

Yes I’m sure the USA government at the time and Congress will be up in arms about it, holding hearings, threatening this or that action, calling it a cartel or anti competitive behaviour or such like.

However no court in the USA is going to find in there favour, so long as the company’s can prove there break even point is near this $7 per MCF. Now if the price went quickly towards say $12 per MCF the courts might take a different view, but the company’s can easily avoid this from happening by simply turning on a few wells again to ensure there is enough supply in the market.

Current Opinion

Industrial demand makes up around 28% of the Natural Gas market, Electric power generation consumes about 31% of supplies, Residential demand accounts for around 22.5% and Commercial demand accounts for around 17.5%.

The average price of Natural Gas in the first half of 2008 was just over $10 per MCF compared to today’s price of $3 per MCF, that’s a saving of $7 per MCF. That’s over $420M a day or $16.5 billion a month as prices continue to fall.

Since August 2008 the cumulative saving to the prevailing price in the first half of 2008 ($10 per MCF) is approximately $440 Billion. Which has fed into the USA economy in various ways.

How long will it last???

No-one knows, but if you had asked me the same question 7 months ago (see my previous comments in Historic section below), I would have been of the view that the change over was just about to start with Natural Gas in storage low & some of the bigger players / producers close to holding most of their key shale gas leases by production. However events since August have shown otherwise.

Looking over all the data and facts I have viewed while I have been writing this update to my thesis, I have come to the view that the window of opportunity for the big players never really opened up the way they or I thought it might. Indeed I was talking to a friend the other day who has lots of connections in the industry and he thought the big players were in a state of denial as to the USA Natural Gas market’s future.

Oil shale formations are undoubtedly king because of the price difference; it could be many years before the USA shale gas plays have any real future. They might have a chance on the international stage, especially if they can enhance production rates a little more or lower drilling and fraccing costs. There is going to be a lot of increased demand for Natural Gas from China, India, Japan etc, in the years to come but there are a lot of LNG projects already on the go or in the planning stage in Australia, Indonesia, Qatar etc and there cost base would appear to be much lower.

This is how I currently see things working out over the next 2 years, the mild winter in the USA causes Natural Gas prices to fall to under $2.25 by end of April 2012. Existing production will quickly start to re-fill the storage facilities. All the oil and gas company’s will be able to see this happening and know that the existing storage facilities will be filled to capacity (currently 4.2 TCF) long before the end of October 2012.

This will cause many of the small and medium sized company’s predominantly focussed on Natural Gas to halt many planned projects and then give up as they run out of cash, or refocus themselves on oil & condensate producing properties instead.

The big players will finally cut their losses and stop trying to hold more leases by production. They will also most likely cut back the production rates of existing wells, to further lengthen their lifespan (and thus lengthen the time the leases are held by production). They will also hope that other company’s follow suit and that Natural Gas prices will recover somewhat. All of this might reduce Natural Gas production from the shale gas formations by 5-8 BCFD by the end of July in a best-case scenario.

Should it happen, it will definitely slow down the build up of Natural Gas in storage, but the amount already in storage by this point in time will be enough to get through the winter of 2012 (the USA can always import some Natural Gas from Canada if need be).

However during this time a record number of new wells will be drilled, fracced and brought into production in the oil shale formations. Natural Gas recovered from these wells as a by-product will start to fill the space vacated by the cut backs from shale gas formations & the Gulf of Mexico production, as well as the closure of old uneconomical wells etc.

I would expect something like 2.5 BCFD of new by-product Natural Gas to be flowing by the end of June from the oil shale formation and that number will continue to rise with each passing day.

Each drilling rig should be able to drill at least 15 new wells in the Eagleford formation during 2012. I expect something like 270+ rigs to be working the formation with lets say average Natural Gas production of 1 MMCFD (million cubic feet a day, those wells located in the oil zone will do less than this and those in the wet gas zone more) per well.

That works out at over 4000 new Eagleford wells in 2012 producing another 4 BCFGD.

In the Permian Basin another 400+ rigs are working there and each rig can drill 24 vertical wells a year although by-product Natural Gas production per well is very small, so the 24 wells combined might only produce 2 MMCFD.

So Permian Basin production will add another 0.8 BCFGD in 2012.

The number of drilling rigs in the Mississippian Play will grow as the year progresses from something like 50 rigs to well over double that number. With each rig drilling at least 12 wells in 2012. It’s a little early to say exactly how much by-product Natural Gas each well will produce on average, but I’ll guess at 0.4 MMCFD for now.

I’d expect something like a 1000 new wells in 2012, which will add another 0.4 BCFGD.

The emerging Austin Chalk play in Louisiana & East Texas will add another 0.1 BCFGD as it starts to ramp up.

So that’s over 5 BCFGD of new by- product Natural Gas production for 2012, and I haven’t even counted anything yet for the Niobrara or Utica shale’s, which will undoubtedly add to this number, or horizontal wells in the Permian Basin.

The Utica shale seems similar to the Eagleford shale but evaluation of it has only really just started, so I’ll watch Chesapeake to see how it develops.

By the time winter 2012 arrives, by-product Natural Gas production from the oil shale formations will have markedly gained market share and taken over close to 5 BCFD of production vacated (or if not vacated soon to be vacated) from the shale gas formation & Gulf of Mexico production etc. This gain will be long term, only lessening as the wells production decline curves kick in. The same level of drilling activity in 2013 will mean a further gain of approximately 3.5 BCFD (the 2013 wells contributing 5 BCFD and the 2012 wells 3.5 BCFD because of production declines in those wells). This will mean over 20% of the Natural Gas market being supplied with by-product production from the oil shale’s.

As for the Natural Gas price, I think it will be below $2.25 per MCF come the end of April and will fall below $2 per MCF before the end of June. I doubt the price will get above $2.50 at all, in the second half of 2012 and will average well under $2.25 per MCF during the period (July – December).

Storage facilities will be filled to capacity and pipeline operators will ask company’s to reduce their production rates accordingly.

In summary, I will go so far as to say I think the USA Natural Gas market is about to implode upon itself in 2012.


Current Interesting Facts

USA Natural Gas production at the end of December 2011 was just under 65 BCFD – A record up by 4 BCFD in just 6 months.

Haynesville Production currently makes up 6.8 BCFD or over 10% of the market and has risen by 1.7 BCF in 2011.

Gulf of Mexico production makes up 7.3 BCFD of total production and continues to fall, lessening the effects any future hurricane in the Gulf would have on the Natural Gas market.

Natural Gas production Per State (figures monthly, translated into approximate daily ones)

Texas 607,096 = 20 BCFD
Louisiana 271,799 = 9 BCFD
Oklahoma 166,00 = 5.5 BCFD
Wyoming 190,000 = 6.2 BCFD

The Major Shale formations and there potential resources

Monterey Shale California 15.4 B BO
Bakken 3.6 B BO
Eagleford 3.4 B BO + 21 TCF

Marcellus Shale 410 TCF
Haynesville 74.7 TCF
Barnet 43.3 TCF

As we move into 2012 Alaska is now talking about building an LNG facility and marketing the LNG in Asia, rather than constructing a 1,700 mile pipeline to connect to the Canadian pipeline system, with it being capable of carrying 4.5 BCFGD (which could be expanded to carry 5.9 BCFGD) onward to the USA as previously proposed by Exxon & TransCanada.



Historic

Trends & Thoughts on the USA Natural Gas Market as at 1st July 2011.

If you go back to the late 1980's and start to work your way forward you will see the price of natural gas swinging from low-high-low-high. Looking at it in price terms the low gas price would roughly have been $1.25 to a high of $3.25 then to a low of $1.50 to a high of $3.50 to a low of $1.75 to a high of over $4.00.

The cycles in those days were much simpler to understand. Most natural gas wells at that time would produce for 4 years maximum with high decline curves.

When the price of gas was low (below $2) company's would postpone projects thus idling rigs as it was simply uneconomic for them to produce gas at those prices for any length of time. As more and more rigs stopped working, less and less "new" gas was added to the storage reserves. At the same time the decline curves of the existing productive wells continued there decline thus decreasing the amounted of gas being produced from all angles. Eventually it reaches a point where supply barely covers demand.

At that point in the cycle the price of Natural gas finally starts to pick up again. As it does company's start to believe they are in for higher prices and start to order rigs and drill wells to take advantage of the higher prices. It takes a little while to achieve all of this and then connect the new wells to pipelines etc. All the time supply is tight and if it is near winter the price will move up more rapidly. This increase in price only encourages companies to drill more and more wells and in a short period of time several hundred rigs will be back in action. This continues to happen until suddenly supply is way ahead of demand and the price starts to drop again. Just as on the down side, operations already started or contracted to start have to be carried out, only adding to the supply glut for several months to come (as the drilling of wells is completed, pipelines built, then tied into production etc).

As you can see this continually causes overshoots in both directions.

In 2005 prices started another upswing which resulted in them at one point reaching over $14 per MCF and prices stayed in the $10-13 range for quite some time when oil prices were above $125+ a barrel. At the same time a number of other factors came into play, there was talk that the USA was running out of natural gas and would need supplies from elsewhere, which is why LNG projects in Australia and the Far East took on much more importance. The Barnett Shale was just emerging at that time as well. The USA economy was growing rapidly creating extra demand.

Oil & gas companies saw the potential of shale gas and started to buy up leases on new plays like the Haynesville & Marcellus Shale, those that got into these plays early did so cheaply, but once word spread of there potential everyone was wanting a piece of the action and lease price rose rapidly, Barnett Shale leases were going for $5-10K an acre, the Marcellus even more and the Haynesville topped out at over $25K an acre. Oil and gas companies sunk huge amounts of capital into these area's including issuing large amounts of senior debt or borrowing from the banks to fund the lease purchases. America suddenly had enough natural gas reserves to last it another 75 years or more.

However along came the financial crisis, which totally threw the oil & gas companies plans out of the window, oil prices dropped rapidly, as did natural gas prices, demand evaporated as the USA economy went into a severe recession. LNG plans were affected as well as they require massive amounts of capital to start with $15 Billion going upto $40 Billion which meant any project that had not reached the point of no return was stopped in its tracks and has been for 2 years.

Companies with shale leases were left in a no win situation (except for the really smart ones who had managed to hedge some production going forward for the next 2 years at $9 & $7 per MCF) their leases required them to drill wells and get the lease into production within 3 years or lose it. Having invested so much money in the leases in the 1st place companies had little choice but to start drill wells, even although they knew the gas they would be selling would be losing them money, but would allow them at least to hold the lease for many years to come. One productive well was required to hold each 640-acre section by production.

Everyone was in the same boat, which just added to the problem because everyone was after drilling rigs and fraccing crews, which simply pushed up the prices that others could charge for there services. Giving the companies even bigger problems to solve.

In 2010 natural gas prices briefly flirted with the $3 level before starting to recover, partly because of the very cold winter.

The standalone natural gas shale plays with no liquids in them really need somewhere near $7 for natural gas just to make a tiny profit. The shale’s which are far more oil prone like the Bakken & Eagleford are dictated to by the price of oil and natural gas is treated as a by-product so its just an extra revenue stream for them.

It takes the equivalent of 6,000 cubic feet of gas to make 1 barrel of oil. Which is normally referred to as the 6:1 conversion ratio however the price differential is very different, go back a number of years and the price ratio might have been 8:1 but it has been widening considerably and recently has been well over 20:1. This is why most oil and gas companies have turned their attention to liquid rich shale’s because it is far more profitable for them.

However back to natural gas and what is happening right now in the middle of 2011, slowly but surely the companies have drilled there Haynesville leases and most are now reaching the point where all of their leases are now held by production. It has been very costly for them but the big players have survived and they are about to turn the tables on the American consumers.......

Now their investments are secured there is no need for them to continue to drill wells as they did previously and flood the market with natural gas. I'm going to use Petrohawk as an example of what's about to transpire over the next few months.

Petrohawk were one of the lucky ones who got into the Haynesville shale at the very start at basement prices and hedged a lot of their future production at that time. So they have not been under anywhere near as much pressure as others, but still had to issue lots of senior debt and sell off other assets to fund the scale of their drilling requirements. Petrohawk have been using 16 drilling rig and each has been drilling roughly one well a month. Each of those wells is starting out at about 8.5MMCFGD with a decline of 50% in the 1st year of production and another 30% decline in year 2. Petrohawk as of June will have all the leases it wants held by production and is going to use only 6 drilling rigs in the Haynesville for the rest of 2011 and is moving its focus to the Eagleford shale where it is going to increase the number of rigs there by about the same amount.

"So what" I'm sure you're thinking, well let me put some numbers in front of you. Petrohawk currently produce 860MMCFGD from the Haynesville (0.86BCFD) Ten less Haynesville wells means 85 MMCFGD less new production in the first month. The increase in Eagleford activity will add under 20MMCFGD of production. In the second month new Haynesville production will be down a combined 165 MMCFGD (85 +80) Eagleford up a combined 37.5MMCFGD (20+17.5) maximum. In month 3 the Haynesville will be down 240 MMCFGD (85+80+75) and the Eagleford up 52.5 MMCFGD (20+17.5+15).

The 6 wells that Petrohawk are going to be drilling in that area, if they were all in the Haynesville would be enough to maintain production at current levels when you allow for the decline curve of all the existing wells they have, in fact it might marginally increased overall production. However a number of the wells Petrohawk are going to be drilling are to test another shale the Bossier shale which partly overlies the Haynesville.

In summary Petrohawk are not actually going to be reducing production by the above numbers, but that is production that could be coming online but isn't because of the price. Add in Chesapeake & Exxon and you could easily be looking at 1 BCFGD that could have been online by October but won't be because of the current natural gas price from 3 big players alone. Yes its only 1 BCFD, but that adds up to 140 BCF over the winter, which is close to 10% of the natural gas that was left in overall storage at the end of this winter.

Chesapeake are currently the biggest user of drilling rigs in the USA and use about 10% of all rigs in use. They have nearly doubled their gas production over the past 5 years and are second only to Exxon with daily production of 2.7 BCFD. They do not intent to increase their natural gas production rate at all over the next 3 years, their aim is simply to maintain it, and they also have one of the biggest lease positions in the USA.

The USA is currently producing around about 62 BCFGD and currently has demand for 53 BCFGD. It is also importing 5.5 BCFGD from Canada and 1 BCFGD via LNG facilities. Net injects into storage are 13% lower than last year and 3.3% below the 5 year average as at 12/6/11.

The gap seems to be about 13.5 BCFD currently depending on the weather, which indicates that injections are likely to be lower than last year. That is before taking into account the possibility of a hurricane tracking into the Gulf of Mexico this year and causing damage to supply.

Can USA consumers currently afford $7+ per MCF for their gas? and what effect will such a price have on the money they have left to spend on other things. That will translate into a near 100% rise in price this winter for natural gas heating etc.

The European gas market doesn't have the same storage capacity etc as the USA so the summer months could be the time the USA gains LNG shipments in future years. Although in winter the European market is likely to be ahead of the USA in shipments because the price of gas is much higher $9+ There is of course the Japanese situation to take into account going forward as well whereby they must be seen as a much bigger market for LNG to keep there power plants running etc. China of course will be a growing market for now as well.

Yes the new oil shale’s are providing some gas into the market and will do for many years to come, over time the cycle from peak to trough should be much more stretched out and far less volatile because you wont have lots of supply with a max production period of 4 years, these shale wells will produce for 20+ years. The gas companies wont get it all there own way as development of the Permian Basin and the Mississippi oil play in Oklahoma provide even more supply of long term gas as a by product from 1000's of new wells.