THE BARRICADE

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 the 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, 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 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 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 counterintuitive,” 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 liquefication-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 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. (Barclay’s Latest view on the LNG-supply to world demand quandry)

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, 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 said Thursday it would shutter 13 assembly plants for up to 11 weeks this summer. Ford Motor Co. 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 the most of the economic growth in the last ten years as 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 dawning of a new source of domestic demand for NG, domestic marginal producers can fuggedaboutit.  LNG will punish them.  Still, the prospect of low nat 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 its not likely that NG will get much support from government “stimulus” efforts of from Dept 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 its doubtful that many domestic producers can weather such a long stretch of very low prices.

We don’t want to change the bankers.  To put new, honest people in charge,  would beg to define the scope of the problem and reveal the cover-up.  Its not so much of a cover-up as an obfuscation by way of direction attention away from the otherwise glaring fact that the people that were in charge of preventing the crisis in the first place are still at the commanding heights of government and banking.  This echos the sentiment consistently expressed by Taleb that we need to replace the current bankers and bank regulators with people who demonstrated the vision to anticipate the problems that we’re in now, rather than promote and consolidate the power of those who were at the helm when the ship ran arground.  This is not a partisan, or ideological issue.  I like O.  I voted for him.  But Geithner, as Paulson did, says that it will take $2 trillion to deal with the banks’ undercapitalization, but they both report that the recipient institutions are “solvent.”

Geithner was one of the top regulators during the subprime lending years, but he heeded no warnings. Way to many liabilities, way too few assets.  Give them a CAMEL rating of (1), FDIC them, fire everyone and put them in receivership.  But, no, that would fuck-your-buddies.  A failed legacy regulator, Geithner denies that he was a regulator at all.  Nevermind, that he was a FED Governor, and the NY FED was charged with regulating the largest banks and bank holding companies in the country.

While its true that the FED had no power to regulate financial instruments themselves nor the derivative trade (nor did anyone else, it seems), financial instruments and derivatives in-and-of themselves were not the problem, its the risk that they represented and the fact that the biggest banks and bank holding companies in the country were massively undercapitalized in relation to that risk.   Trade all the bullshit CDO’s you want, as long as you have the reserves to absorb their defaults.  Oh, and CDS’s don’t count because they’re not money.  Would it matter what AIG did if the banks were honest about their balance sheets? The gaping under-capitalization of the big banks falls squarely in the area of the FED’s regulatory responsibility.  True that I-Banks were not then subject to the same regulatory scheme, but even if they were, would it have mattered given the regulatory posture during the height of the largest asset and credit bubble of all time?  They didn’t see the liabilities, and therefore could not accurately determine whether the biggest institutions were adequately capitalized.  Maybe they didn’t bother to see, because the too-big-too fail idea was so pervasive.  Maybe they didn’t want to. Wonderful discussion of this, here:

Three federal banking agencies, the Federal Reserve Board, Office of the Comptroller of the Currency, and FDIC, along with state banking departments or commissioners, are the regulatory agencies for bank market regulation.  At the federal level, the Comptroller is the oldest agency, which has served since the [war time] Banking Act of 1863 as the chartering authority for national banks, and their primary agency for supervision and examination.  The FDIC became a collateral supervising agency in 1933 for all N.A.s. and anyone seeking FDIC insurance.

The Federal Reserve Board, created in 1913, also has supervision and examination authority for state chartered member banks, and since then has become the most important agency because it is the agency that has been given the most general power under subsequent statutes covering mergers, bank holding companies, truth-in-lending, fair credit reporting, and certain aspects of multinational banking.

So, while it is true that other agencies frequently have had overlapping regulatory authority, including with the OTS, its clear that as the lender of last resort (after all, the FDIC has a limited pool of money to work with) and as the agency with the widest authority to look after bank solvency, the FED is surely a regulator, and should be considered the regulator of first and last resort when it comes to money.

Wither the FED? Is it even constitutional?  I suppose we have to have a FED if the world is going to be on a the Dollar Standard.  The Dollar Standard is, of course, a bubble, and it will burst with much bloodshed and gnashing of teeth, but that’s the subject of another post.

NG will become a global commodity in a world of past-peak Oil.  Do any readers know of where to find decline information re Ghawar? Very good insight  below from: http://seekingalpha.com/article/127670-the-globalization-of-natural-gas. See also, post: “World Oil Production Has Peaked, not so for Natural Gas” on March 24th.

The Globalization of Natural Gas:

A lot of people toss “crude oil” and “natural gas” into the same “energy” hamper, but they actually have quite different constructs in terms of demand/supply dynamics. It can most simply be described as the difference between an easily transportable, global commodity (crude oil) versus one that is not (natural gas). Hence the latter’s supply/demand dynamics have been historically more focused on the localized economy. Put another way, in periods different from now when the entire globe is contracting - natural gas could be holding up in one part of the world, whereas it would be struggling much more in other parts. Versus crude oil which can be shipped quite promptly to wherever shortages are. This is also why Russia has Europe’s cajones in an iron grip - since Europe is so dependent on Russian natural gas; and cannot turn to a “global supply” like they could with oil.

The decline in crude oil prices gets all the headlines, but the first globalized natural gas glut in history is driving an even more drastic collapse in the cost of gas that cooks food, heats homes and runs factories in the United States and many other countries.

Six giant plants capable of cooling and liquefying gas for export are due to come on line this year just as the economies of the Asian and European countries that import the most gas to run their industries are slowing. Energy experts and company executives say that means loads of gas from Qatar, Egypt, Nigeria and Algeria that otherwise would be going to Japan, Korea, Taiwan and Spain are beginning to arrive in supertankers in the United States, even though there is a gas glut here, too.

With industrial and utility use of natural gas declining, gas prices in the United States have already declined by two-thirds since the summer. Prices are not likely to go down much more, experts say, but an increase in imports is likely to keep them low until the global economy recovers and drives demand back up. That is good news for American consumers and many businesses, since gas provides about a fifth of the power generated by electric utilities and is a vital component for fertilizers, plastics and other industrial products. But it is bad news for proponents of energy independence, who cheered the boom in domestic gas drilling and production over the last four years.

Natural gas is becoming a world commodity like oil. It is still loosely connected to world oil benchmark prices and its price, usually set by longer-term contracts everywhere except for the United States and Britain, can diverge widely from one continent to another. Until the last few years, liquefied natural gas was a high-priced necessity for countries that did not produce their own gas supplies or have access to piped reserves; but it now has become a cheap economic driver for countries like Japan with few energy resources.

But as more terminals have been built, the amount of gas that is shipped from one continent to another in giant tankers has climbed. And now the emergence of the global market in gas is about to take a giant leap. The global capacity for liquefied natural gas exports of 200 million tons a year will increase by 25 percent with the completion of six new plants in Qatar, Russia, Indonesia and Yemen, totaling $48 billion in investments, and the upgrading of a seventh plant in Malaysia. More large plants are due on line in 2010 and 2011.

Natural gas in the United States costs a little over $4 per thousand cubic feet, down from a peak of more than $13 last year. On average, world spot prices for liquefied natural gas cargoes have come down by more than two-thirds since last summer.

THE BIGGEST GAS WELL IN THE WORLD

The world is now awash in natural gas. Most in the industry agree that world’s oil production capability peaked several years ago.  For example, the second largest field in the world–Mexico’s Cantarelle–declined at a rate of 19% last year.  But new discoveries show that the world supply of natural gas may have a long way to go before seeing a peak.

While recently most industry attention has been paid to the sharp increase in U.S. domestic unconventional production, that now seems like child’s play compared to the production being reported by Inter Oil’s Antelope One in New Guinea–see full story below.  The statistics about this well are staggering, and should leave mouths agape.  Anetelope as the theoretical potential to produce well in excess of 10 billion cubic feet per day.  Such a find has the potential to be insanely profitable even if gas prices plummet to all time lows.  The value of such a well in a time of high gas prices is staggering to compute.  This discovery is momentous for world LNG trade, and provides further fodder for those advocating that NG be utilized as a alternative transportation fuel in a world from which crude is fast disappearing.

http://seekingalpha.com/article/127595-interoil-introducing-the-biggest-natural-gas-well-in-the-world

InterOil (IOC) is a Canadian integrated (exploration assets, refinery, near distribution monopoly) located in Papua New Guinea [PNG]. After having struck two earlier profusely flowing natural gas and liquids wells (flowing at 102 and 105MMcf/d respectively), they hit an absolute killer with Antelope1, which flowed at a whopping 382MMcf/d.

Record well
Summing up a few findings:

• 382MMcf/d with the pipe only 30% open for safety reasons, and the log indicated that the permeability at the top did not allow the lower section of the reservoir to contribute to the flow test. That is, all the gas just came from the top 12% of the reservoir
• 5000bb/d in condensates
• 792 meters (2300ft) of net pay zone, which is more than three times the size of the biggest American well (650ft), and the gas / water contact has not even been determined yet
• The largest calculated absolute open flow [CAOF] at 17.7 Billion cubic feet of natural gas per day
• 8.4% average porosity
• From the seismics, the Antelope field is 14 x 7 kilometres

Let’s put that in perspective
Just three wells flow 600MMcf/d, more than enough to supply the daily needs of an LNG facility. This is roughly equivalent to the daily productivity of Southwestern Energy (SWN), enterprise value of 10.5 billion. It is larger than the daily production of Ultra Petroleum (UPL), enterprise value of roughly $6 billion. The record-breaking well by itself has larger daily production than the entire corporation of Range Resources, enterprise value $7.3 billion.