Amazing North Dakota Sets More New Oil Records in August as Production Doubles in Only 26 Months
1. A new record for monthly production: 13,768,395 barrels, a 34.6% increase from last August. In just a little more than two years (since June 2009), oil production has doubled in North Dakota (see chart above).
3. A new record number of wells producing: 5,702.
4. New records for barrels per well (per month): 2,415; and per day: 78.
5. A new record for oil-related jobs: 16,200 (see chart), which is more than double the number of North Dakota oil jobs at the beginning of last year.
At North Dakota's blazing current pace of monthly increases in oil production, the state will be producing more than 560,000 barrels of oil per day by January 2012 and will then pass #3 California (540,000 barrels per day) and #2 Alaska (550,000 barrels per day) to become America's second-largest oil producer. North Dakota Department of Mineral Resources Director Lynn Helms is even more optimistic and predicts that the Peace Garden State could actually be producing as much as 800,000 barrels per day by the end of this year!
North Dakota's impressive economic success clearly illustrates the huge benefits of domestic energy production: more jobs and the lowest jobless rate in the country, record economic growth, huge gains in personal income, and even more tax revenues. There's no reason that the economic success and ongoing job creation in North Dakota can't be duplicated elsewhere, if more U.S. land and off-shore areas were opened up to domestic energy exploration and drilling. Drill, drill, drill = jobs, jobs, jobs.
26 Comments:
So if North Dakota oil production doubles every 26 months....in five years, in 10 years?
If only, if only.
Ohio will be the next North Dakota, northeast Ohio in particular. South Texas and San Antonio are already in catch-up mode to ND.
what does alaska's production look like over the past decade?
In 2011, the trans-Alaska pipeline is forecast to carry less than 600,000 barrels a day of oil, compared with peak of about 2 million barrels. Flow rates are expected to continue to decline at about 6 percent a year.
http://seattletimes.nwsource.com/html/businesstechnology/2014601450_alaska27.html?syndication=rss
That's about 3.4% of our current use, I believe.
Or, less than half of what we get from ethanol.
Come now Mark, why can't you do the math?
First, if we look at the reports we find that the average completed well costs range from around $5 million to $9 million per well. That is not cheap.
Second, new wells produce about 2,000 BOE per day equivalent over the first quarter of operation. (Note that is a BTU equivalent, not a price equivalent. Most wells are gas rich and liquids poor. Given the price of less than $3 at the well head for gas and the $7 break even requirement it is clearly easy to see why the companies are emphasizing the liquids side.)
Third, the production data shows a massive depletion rate for shale wells. This is why the average well is producing only around 78 BOE per day. That production level would be considered very poor for conventional fields where drilling costs are very low. I do not see how it merits excitement just because it comes from expensive to drill shale formations.
Forth, the industry is consuming cash very rapidly but has little in the way actual profit to show for its activities. The only 'profits' come from unsupported EUR assumptions that are clearly too high once the production data has been analyzed.
The jobs story is a very good one but if those jobs are unsustainable, as the housing jobs were, why get excited and cheer on the capital destruction? Unless one is trying to find short opportunities or hoping to cash in on the long side of the conventional producers once the hype is exposed I see no way to justify the wishful thinking and the hype.
Here we go again with Vangel's ignorant comments, which I pointed out to him before, but which he conveniently has forgotten, or neglected to read.
1. The 78 BOE per day statewide for North Dakota includes hundreds or thousands of old stripper wells, some dating back decades, which produce a few barrels of oil per day. The 78 BOEPD is not representative of Bakken wells, because the statewide average is being held down by large numbers of legacy wells.
2. But if you insist on mentioning it, that 78 BOEPD average is the highest number since June of 1953. Now, if Bakken wells were such miserable failures, how the hell could average daily production have doubled in a little more than 3 years?
3. No, that production level would NOT have been considered poor for conventional wells. See data from 1950's to 1990's above. During the entire period from the mid-50's until the past couple years, 78 BOEPD would have been considered excellent. So excellent, in fact, that that level did not remotely reach that output for 50 years.
4. Before deluding yourself that this oil isn't profitable, feel free to look at some recent earnings statements from EOG, Continental Resources, Whiting Petroleum, etc etc.
1. The 78 BOE per day statewide for North Dakota includes hundreds or thousands of old stripper wells, some dating back decades, which produce a few barrels of oil per day. The 78 BOEPD is not representative of Bakken wells, because the statewide average is being held down by large numbers of legacy wells.
You have to pay more attention. By my count 185 wells were officially decommissioned in 2006 and 244 in 2007. Legacy wells do not last very long unless they are in the original sweet spots in the formation. Because the original targets were prolific the wells were not expensive horizontal wells and were very profitable. That is not the case with $5 to $9 million new wells that deplete very rapidly and produce mostly gas.
2. But if you insist on mentioning it, that 78 BOEPD average is the highest number since June of 1953. Now, if Bakken wells were such miserable failures, how the hell could average daily production have doubled in a little more than 3 years?
Easy. There is a drilling boom in ND that is increasing the number of new wells very rapidly. New wells start out producing more than 1,000 BOE per day in the first quarter. Even though the depletion is brutal a high number of new wells will cause the average to go up, particularly when there is an ever growing number of old wells being decommissioned, a factor that you seem to ignore.
3. No, that production level would NOT have been considered poor for conventional wells. See data from 1950's to 1990's above. During the entire period from the mid-50's until the past couple years, 78 BOEPD would have been considered excellent. So excellent, in fact, that that level did not remotely reach that output for 50 years.
Sure it would. A good well in a conventional field, (shale formations are not conventional), produces over 10,000 bpd and depletes very slowly. A good well in a shale formation costs millions more to drill and produces 3,000 BOEpd the first quarter. By the end of the first year production levels are in the hundreds BOEpd.
You seem to be thinking of the stripper wells that you see all over the US and are producing less than 10bpd. But those were cheap vertical wells that were paid for decades ago, not multi-million dollar wells that will not generate a profit.
4. Before deluding yourself that this oil isn't profitable, feel free to look at some recent earnings statements from EOG, Continental Resources, Whiting Petroleum, etc etc.
What there the EURs? Does the production data support them? And what were the cash flows? Why did the companies have to borrow massive amounts or issue equity if the ventures were truly profitable?
"That is not the case with $5 to $9 million new wells that deplete very rapidly and produce mostly gas."
Yes, these wells are expensive. So what? Assume an EUR of 200K barrels. At $80 oil that's $16 million. If, as many companies say, the EUR's of these wells are often closer to 300K or 500K barrels, that's $24 million to $40 million. No wonder they're drilling so many of them. Duh!
The wells in the Bakken do not mostly produce gas. By energy content they're more like 80% oil. Don't confuse the Marcellus with the Bakken.
"Sure it would. A good well in a conventional field, (shale formations are not conventional), produces over 10,000 bpd and depletes very slowly."
Dude, you are so full of crap it isn't funny. Look at the very North Dakota data we've been discussing.
** April 1951 - 1 producing well - daily oil per well = 103 bpd
** The single best month is January 1952 when 1 producing well produced an average of 231 bpd that month.
After that, it's all downhill. These are all conventional wells. If you cared to learn about actual US onshore oil production history instead of just reading the propaganda at The Oil Drum and Energy Bulletin, you'd learn that wells producing more than a few thousand bpd are fairly rare. There are some oil fields in the Middle East which have clusters of wells in good spots which produce numbers like those, but those are the exception, not the rule. Only when you get offshore in deep water with super pressures do you frequently get wells over 10K bpd.
"What there the EURs? Does the production data support them? And what were the cash flows? Why did the companies have to borrow massive amounts or issue equity if the ventures were truly profitable?"
I can show you countless estimates of EUR's of Bakken wells from all the companies I listed, and more. The numbers I listed above are in that range. However, you've already said you don't believe the companies' states EUR's, so you're hypocritical to ask me for something you've already said you don't believe.
Here's some info on Spindletop in Texas, which is the kind of oil field touted by Peak Oil Propagandists as one of the exemplary fields in Days of Yore.
In 1902, Spindletop produced a total of 17,500,000 barrels - which would be 61,403 bpd for the entire field. With 285 wells that would be a whopping 215 bpd per well! By 1904 the field had dropped to just 10,000 bpd, or a jaw-dropping 35 bpd per well (assuming the same 285 wells).
I can go on with many more examples like that. A typical conventional onshore well in the US is lucky to average 300 bpd, even when it's young. Yes they deplete slowly, but you get less oil initially than your typical Bakken or Eagleford well. Ultimately they even out - and the more modern Bakken wells might even have an advantage. The East Texas Oil Field, for example, has produced 5.2 billion barrels from a total of 30,340 historic and existing wells. That's an EUR of 171,390 barrels. Maybe when all is said and done in a few decades they'll get up to 200K barrels ... which is on the low end of Bakken wells.
I repeat: VangelIV has no idea what he's talking about. He spends too much time reading the propaganda from Energy Bulletin and The Oil Drum.
The fact remains, it will become increasingly harder and more expensive to extract oil, because cheap oil is being depleted quickly.
If the U.S. didn't have the weakest economic recovery in history, oil would've reached $150 a barrel again, or more, because of Peak Oil.
Technology will continue to improve. Nonetheless, global production will decline and prices will rise. We reached Peak Gold a decade ago. However, the technology hasn't improved enough to even replace lost production.
The higher price of oil caused the ND production boom, which began in 2008, as the chart shows. Even if oil reaches $200 a barrel, I doubt unconventional oil production will replace cheap oil depletion fast enough.
Yes, these wells are expensive. So what? Assume an EUR of 200K barrels. At $80 oil that's $16 million. If, as many companies say, the EUR's of these wells are often closer to 300K or 500K barrels, that's $24 million to $40 million. No wonder they're drilling so many of them. Duh!
But that is the problem. You can assume any EUR that you want. But if you look at the actual production data the EUR assumptions are too high. The reported data is actually BOE and includes a gas component at around 6:1 based on BTU differences. But if we look at the price ratio we see that the real ratio should be around 20:1. That is a huge difference. Put the two together and you understand just why so few companies can make a profit from drilling shale formations. Unless you are in a sweet spot you will have to keep borrowing or issuing equity because at the current prices you will be destroying rather than creating capital.
The wells in the Bakken do not mostly produce gas. By energy content they're more like 80% oil. Don't confuse the Marcellus with the Bakken.
I am not. I am simply pointing out that the assumed EUR figures may not be reflective of reality. And I have noted that in the past Mark was also citing articles and commentaries that were hyping Marcellus, Haynesville, Barnett, Eagle Ford, and Fayetteville shale areas. All of those have turned out to be losers from the capital formation side.
And I have pointed out that where one drills is very important. The Bakken formation has porosities that range from close to zero to around 10%. The older wells were drilled in areas that had favourable porosity and permeability of around .01 millidarcies. That made the early wells profitable even at low prices and provided depletion curves that were quite favourable. Most of the newer wells do not fall in that category, which is why the assumed EURs are likely to be too high.
Dude, you are so full of crap it isn't funny. Look at the very North Dakota data we've been discussing.
** April 1951 - 1 producing well - daily oil per well = 103 bpd
** The single best month is January 1952 when 1 producing well produced an average of 231 bpd that month.
Dude, ND is not a conventional reservoir. It is a shale formation. If you want to see what a decent oil well produced you have to go and look at the time when the Texas, Oklahoma, and California fields were developed. The Lucas well in Beaumont, Texas had an initial flow rate of 100,000 bpd. Because of the unfavourable porosity and permeability characteristics of shale formations production from shale wells is very low. That is why you need to spend $5 to $9 million drilling horizontal wells and fracking.
After that, it's all downhill. These are all conventional wells. If you cared to learn about actual US onshore oil production history instead of just reading the propaganda at The Oil Drum and Energy Bulletin, you'd learn that wells producing more than a few thousand bpd are fairly rare. There are some oil fields in the Middle East which have clusters of wells in good spots which produce numbers like those, but those are the exception, not the rule. Only when you get offshore in deep water with super pressures do you frequently get wells over 10K bpd.
There is nothing 'conventional' about shale formations. And wells that produce more than a few thousand barrels are not rare in good formations that have not been exploited. They are rare in very mature formations or in uneconomic unconventional areas.
I can show you countless estimates of EUR's of Bakken wells from all the companies I listed, and more. The numbers I listed above are in that range. However, you've already said you don't believe the companies' states EUR's, so you're hypocritical to ask me for something you've already said you don't believe.
I have been watching the EUR game for quite some time now. I am asking for evidence that the estimates are correct. On this site I have already pointed out Arthur Berman's work on a number of the shale formations that Mark was hyping. For the horizontal wells in the Barnett formation Berman showed that the average EUR was approximately one-third of what the operators were predicting. I see no reason to believe that the same companies will be any more accurate in the Bakken formation. If they were, the success would show up in the cash flow reports, which include no estimates.
Here's some info on Spindletop in Texas, which is the kind of oil field touted by Peak Oil Propagandists as one of the exemplary fields in Days of Yore.
In 1902, Spindletop produced a total of 17,500,000 barrels - which would be 61,403 bpd for the entire field. With 285 wells that would be a whopping 215 bpd per well! By 1904 the field had dropped to just 10,000 bpd, or a jaw-dropping 35 bpd per well (assuming the same 285 wells).
In 1901 the Lucas well was capped. It was a gusher that produced 100,000 bpd initially. Capped wells count as zero production. And in 1901 the wells were very shallow and primitive. Use a horizontal well and spend $5 million and you will get 50,000 plus for the average well, even without fracking.
I can go on with many more examples like that. A typical conventional onshore well in the US is lucky to average 300 bpd, even when it's young. Yes they deplete slowly, but you get less oil initially than your typical Bakken or Eagleford well.
This is not true unless you are talking about very old conventional fields as you are in the long producing areas of the US. And in this game the issue is profit. That means that you have to put in less energy in drilling, developing, producing, and transporting the oil than the energy you get out of the oil. In the case of shale ares the return is negative in most cases, which is why the cash flows are negative years after the industry began operations. Nobody got rich by destroying capital, which is what shale production still does.
Vangel, you are indeed poorly informed.
The Bakken wells of the last several years, contain an average mix of 85/15 oil..
Furthermore, there are NO DRY WELLS, and each new find will have a thirty year production of 500,000 barrels over its lifetime..
http://milliondollarway.blogspot.com/
As Al Gore would say, please go to this website and inform yourself...
Vangel you clearly have no idea what you're talking about, because your responses to my comments habitually changed the subject.
Once again, I can show you EUR estimates and decline curves of Bakken wells from the companies who drill them, but if I do so you tell me you don't believe them. If you don't believe them, don't ask me for them, idiot.
An uncontrolled gusher well is not indicative of a producing well. If they let Bakken wells flow uncontrolled with completely open chokes, you'd get plenty of those gushing 10,000 bpd too.
And as further proof of your idiocy and ignorance, the 1951 well production figures I cited were conventional oil fields. They did not even *have* unconventional oil production back then, and there most certainly are plenty of conventional reservoirs in North Dakota. Those 100-200 bpd wells in the 50's were producing mostly from conventional fields. Please educate yourself before you make any more ignorant comments.
The Bakken wells of the last several years, contain an average mix of 85/15 oil..
So? The 15% is counted as a 6:1 BOE when prices are worse than 20:1.
Furthermore, there are NO DRY WELLS, and each new find will have a thirty year production of 500,000 barrels over its lifetime..
Thirty years? How do you know that? Haven't you learned anything from the shale gas hype? The wells were supposed to have 40 year lifespans. Things did not turn out that way.
http://milliondollarway.blogspot.com/
As Al Gore would say, please go to this website and inform yourself...
OK, let us look at your reference. We find an interesting comment.
18691, 3,731, Newfield, Wisness Federal 152-96-4-2H --- 35,849 bbls in first 25 days. Okay. Westberg field, Bakken. One section spacing. Middle Bakken at 10,573 feet. 26 stages. 2.2 million pounds of proppant (I don't know if this was sand only, which would be unlikely); no acid. S4/11; T7/11; cumulative 61,336 bbls in 53 days (less than 2 months); total depth 16,012 feet; fracked "on time." Sand only. I.N.C.R.E.D.I.B.L.E.
Did you do the math? The IP of 3,731 shows a rapid decline. After 25 days the average is down to 1,434. That is a 60% drop in less than a month. If that is incredible the people who are hyping up the well are not very good investors. They are just promoters looking to talk up overvalued reserves so that a greater fool can take their shares off their hands.
And if you look at Newfield you find that the company pays no dividend and is burning a great deal of cash. Its profits are only going up because it is not depreciating its reserves quickly enough thanks to a very favourable EUR assumption. This is the same game we saw with the shale gas producers over the past few years ago.
I suspect that when people look at the shale players a few years from now they will see the same type of mountebanks and frauds as they do when they look at Al Gore and the AGW industry.
Once again, I can show you EUR estimates and decline curves of Bakken wells from the companies who drill them, but if I do so you tell me you don't believe them. If you don't believe them, don't ask me for them, idiot.
I can show you estimates for other shale areas. But as Art Berman pointed out, they do not match up with the production data. Now it could be that the companies that work the Bakken are a lot smarter and more honest than those in the other shale areas. But if that were the case you would see decent dividends and positive cash flows. I don't know about you but I don't see many.
An uncontrolled gusher well is not indicative of a producing well. If they let Bakken wells flow uncontrolled with completely open chokes, you'd get plenty of those gushing 10,000 bpd too.
Possibly but I doubt it. The Bakken formation has good source rock but a poor reservoir thanks to unfavourable porosity and permeability characteristics. This matters.
Now you could argue that you make up the shortfall by using horizontal drilling, a huge surface area, and fracking. But that is not an apples to apples comparison because you are looking at a modern well that costs multiples of what the old wells used to cost. And keep in mind that some of the old wells produced little because the companies did not drill deep enough. All they had to do to increase the production rates is to drill a slightly longer well. That is not the case for shale formations that have such poor characteristics.
Why you don't understand any of this is a bit of a mystery. Not to worry though. All you need to do is read up on the subject.
And as further proof of your idiocy and ignorance, the 1951 well production figures I cited were conventional oil fields. They did not even *have* unconventional oil production back then, and there most certainly are plenty of conventional reservoirs in North Dakota. Those 100-200 bpd wells in the 50's were producing mostly from conventional fields. Please educate yourself before you make any more ignorant comments.
You are still comparing cheap vertical wells that deplete slowly in a poor reservoir to $5-$9 million horizontal wells in a tight formation that deplete rapidly. And you seem to have forgotten the history of the oil bust in the 1980s because even the cheap wells could not be justified given the poor characteristics of the formation.
You need to read some more. Try looking at Texas, California, Oklahoma, Ohio, and other oil producing areas and see just how profitable they were even at very low prices.
The last update daily production by the end of the years, will be 535,000 bpd...
The 800,000 bpd was an error and a bad one at that..
Vangel, the latest projects from the industry, I assume, state the average well will produce over 500k during its production cycle...
Hear are some more figures, that show most will producing 80k per year..
http://milliondollarway.blogspot.com/2011/06/rig-utililization-in-bakken-north.html
Vangel, are you suggesting that this is the case with Bakken Wells?
"Most wells are gas rich and liquids poor."
Vangel, are you suggesting that this is the case with Bakken Wells?
"Most wells are gas rich and liquids poor."
Sorry, no. I have been posting on shale production for a while and sometimes say something for one formation that is not right because I am thinking of another. That said, you do have a certain percentage of the resources that come from gas at a BTU based BOE ratio of 6:1 instead of the price based 20:1 ratio that is far more appropriate. That removes a chunk of the resource from the assumptions given. But the bigger problem for the industry have been the low depreciation rates thanks to very unrealistic EURs.
When it comes to risking my own capital I care little for the hype because I am not trying to play a role in the game of finding a bigger fool. What I care about is operational performance. And on that front the unconventional shale plays fail miserably because all I see are negative cash flows from operations even for players that have been producing for quite some time. Now I may turn out to be wrong but I do not see how the shale players, even if successful, turn out to be better bets than their far more conventional peers in the industry.
more jobs and the lowest jobless rate in the country, record economic growth, huge gains in personal income, and even more tax revenues.
auto-transport/
Vangel, thank you for reply..
I do not understand all of those metrics, however, the Bakken is primarily an oil field..
http://www.forbes.com/sites/christopherhelman/2011/06/27/tycoon-says-north-dakota-oil-field-will-yield-24-billion-barrels-among-worlds-biggest/
I do not understand all of those metrics, however, the Bakken is primarily an oil field..
http://www.forbes.com/sites/christopherhelman/2011/06/27/tycoon-says-north-dakota-oil-field-will-yield-24-billion-barrels-among-worlds-biggest/
Yes, it is primarily an oil field. But when doing your analysis you have to look at everything. That includes the 15% or so of BOE reserves that come from natural gas for a number of the producers. As I said, the problem with that number is the 6:1 ratio used when reporting BOE. The price ratio is actually closer to 20:1. This means that you take 10% off the reported reserves for most of the players who have a 15% gas component.
But then we get to the other part of the issue; the reporting of the oil reserves. There is no SEC requirement that is the equivalent of Canada's National Instrument 43-101, which was put into place to reduce the scams that were (and still are) common in the mining industry. In fact, the SEC has been going the other way by relaxing the standards so that it could 'stimulate' activities in unconventional areas like shale.
If you looked at the SEC's previous definition of reserves you would have noted that the oil and gas had to be present in the formation at concentrations that would allow the fluid to flow to the gathering well. The SEC also required that companies drill test wells that proved that the oil/gas was in place. (That is where the term 'proved reserves' comes from.
The recent SEC changes allow companies to make all kinds of assumptions by guessing about future outcomes. So far, the changes have allowed the shale gas producers to overestimate profitability by assuming much higher ultimate recoveries than are actually observed in the data. While the old Bakken wells in the better areas are fine and should produce decent returns, those areas have been drilled for a long time and are now fairly down the aggregate production curve. We do not know with much certainty just how well the newer horizontal wells will do over time. This has to do with the need to use fracking to open up the formation and provide a path that will allow the oil to flow to the well. But the fractures close up fairly quickly and the shale wells deplete much faster than the companies assume. That means that depreciation costs are significantly higher and that many wells that are expected to provide decent returns will not be profitable at all.
Keep in mind that the relaxations of the recognition rules will allow many of the promoters to claim much larger reserves than are actually in place. While that should allow more capital to flow to the sector and production to increase it will not change the true economics of the production process. Eventually you will see major write-downs and many of the companies will find that their negative cash flows cannot be maintained indefinitely.
Vangel, excellent post indeed! Your insights and arguments are all good points, but please remember that attempting to estimate underground reserves, is a most difficult task at best..
The fact remains, however, is Vangel Oil & Gas, was going to spend up to $9 - $10 million dollars on a well, without a fairly good assumption of a return on investment.?
No operator is going to play pig-in-a-poke and remain a viable entity for long.
Furthermore, the longer that drillers continue to refine their exploration methods, the more the likelihood of ever higher IP's and gross production..
I suspect $5 to $10 billion will be spent next year in Bakken capex: If they wanted to simply roll the dices, they would drill in Las Vegas..
Vangel, excellent post indeed! Your insights and arguments are all good points, but please remember that attempting to estimate underground reserves, is a most difficult task at best..
That is my point. It is difficult, which is the reason why you need to do a whole bunch of work before you can say much with certainty. But the new SEC rule changed all that. Right now very little work has to be done for a company to make claims that could be off by several hundred percent.
The fact remains, however, is Vangel Oil & Gas, was going to spend up to $9 - $10 million dollars on a well, without a fairly good assumption of a return on investment.?
You are assuming that a company is going to make a return from production profits. But that does not have to be the case thanks to another SEC rule that allows large companies to overstate BOE reserves by using the 6:1 ratio instead of the actual price ratio. You are also assuming that the people who are running the companies do not have an incentive to play the game while the bubble is being blown up. But I do not believe that is the case. Insiders can make a huge amount of cash by simply selling off parts of their companies to other investors or by agreeing to a takeover by a large company with reserve issues.
No operator is going to play pig-in-a-poke and remain a viable entity for long.
Take a look at the way the industry has been operating. You drill a few holes. You release your reserve estimates and your EURs and you sell your property for $50,000 an acre to a large producer looking to figure out a way to deal with falling reserves. The large producer does not care about the operational losses because it has plenty of very profitable operations that will give the returns that investors are looking for. The value of the shale properties comes from the high reserve estimates, not any profits that they will generate.
Furthermore, the longer that drillers continue to refine their exploration methods, the more the likelihood of ever higher IP's and gross production..
But that has not been the case. As Arthur Berman pointed out, the real world data shows that since 2003 the average well performance for horizontal wells has 'decreased consistently.' It is true that some improvements, particularly due to the better 3D seismic data and targeting drilling have improved yields. But those yields come from poorer formations, which is why the EURs from core areas of a formation are significantly higher than the average EUR of the formation.
I suspect $5 to $10 billion will be spent next year in Bakken capex: If they wanted to simply roll the dices, they would drill in Las Vegas..
As I wrote before, the SEC rules show us that it makes sense to consume capital by drilling money losing wells because the value of those wells do not come from profitability. Don Coxe has been talking about this for years now as have people like Art Berman and Bill Powers. Clearly the industry insiders will not lose from participating in the shale gas bubble. They will take their profits and use other people's money to take the bigger risks. When they game is over they will be much richer than they could have been had they not participated.
What prudent investors, who are not insiders, need to do is to figure out why they should participate. If you are a trader and are hoping to find a greater fool to take your shares off your hands there is no problem as long as you can execute your plans. But if you can't get out when the bubble bursts you will be in the same position as those who bought IT or housing stocks during the latter stages of those markets. My argument is that if you really like energy there are much safer ways to play the game.
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