Shale profitability

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16 minutes ago, footeab@yahoo.com said:

Take Ilumina(ILMN) which I own as an example.  They record profit every quarter, new dominating products, and the stock price drops like a rock.  WHY?  Because some gambling dufus in some ivory tower who has a position of influence stated profit at 2X actual....

Sorry, I wouldn’t trust any company that doesn’t present their financial numbers honestly. As an investor I would assume the entire management is dishonest. 

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28 minutes ago, DanilKa said:

Quote from the above article; “Unfortunately, for the majority of investors holding EOG debt, they will not receive the return of their funds.” Long term debt referred to in the article almost 7 bil, now 4.1, is he just wrong?

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9 minutes ago, Tootired said:

Long term debt referred to in the article almost 7 bil, now 4.1, is he just wrong?

It’s a simple math - integrate FCF over entire period. After that you’ll need to estimate future revenue from declining production (assuming no more drilling) minus operating costs and future obligations, including PnA and debt repayments. Good if that number is positive. 

This have little to do with stock price dynamics - which is human behaviour and narrative management 

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7 minutes ago, Tootired said:

Quote from the above article; “Unfortunately, for the majority of investors holding EOG debt, they will not receive the return of their funds.” Long term debt referred to in the article almost 7 bil, now 4.1, is he just wrong?

Yes, unless something unforeseen and awful occurs to EOG, he's badly wrong. This is part of the old Enron, the honest part. They don't refer to EOG as the "Apple of Oil" for nothing. They're paying down debt, hitting some monster wells, and this man who said that about it may be poorly informed, down on all shale, or has some ulterior motive, I don't know. I don't own any EOG stock, for the record. i suppose EOG could decide to default on their debt but they'd never be able to access the credit markets again. It's easy to hate anything attached to Enron, because there were so many dishonest gunslingers in that company when it finally went belly up, but the very old Enron, the old pipeline company in Kansas, was the Gold Standard in pipes back in the day. Anyway, I'm no cheerleader for EOG but Mark Papas was and is a great oilman and he put EOG on the map. He's gone but his legacy there is intact. That said, I'd be very surprised if one of the super-majors doesn't pick up EOG, not only to get their mitts on good acreage but their superior technology and work force as well. EOG's one great weakness? They don't own a refinery or a petrochemical plant. As all of you know, when the price of oil is low, those two facilities make money. One of my greatest fears of having the super-majors take over shale is that they will, as Harold Hamm put it, drill the whole shebang into oblivion, all the whilst buying acreage on the cheap from the vanquished, profiting mightily by dent of refining and petrochemicals. I'm probably overthinking this but that's what's in my head. Right now, however, anyone who takes over EOG is going to have to pay a premium.

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5 hours ago, Tootired said:

Re Art Bergman: Ya and there are engineers who are out there who say that the twin towers was a controlled detonation, scientists who prove the moon landing never happened, PHD’s who claim that climate change doesn’t exist etc.

Mate, you’ve choose poor examples to demonstrate your point... :) (except for the moon landing which demonstrably happened)

as for the shale and economics - I’m working in the field and graduated in both. Art and Steve represent extreme opinion however there is more truth is saying tight oil (incorrect to call it shale; higher permeability is required to produce liquids) is financed by new investors, i.e. have one of the indicator of a Ponzi scheme. I do not call it such, it is legitimate business and could be profitable with right technology (little used; copy-paste what neighbours do and little engineering) and financial discipline. Cost of acreage and royalties agreement play a big part. 

Hope EOG could remain FCF-positive and turn profit to its early investors. 

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6 hours ago, Gerry Maddoux said:

For example, carbon dioxide injection down the well-bore has been great, as has injection of methane and ethane gas.

Methane reduces recovery and CO2 is second best to ethane+

Issue with EOR in Tight Oil is reservoir topology - can’t pump it from well to well hence have to huff n’ puff 

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9 hours ago, Gerry Maddoux said:

An excellent well with a big IP is usually thought to have a lifetime yield of about 600,000 barrels, which even at $50/barrel (which can't go on forever, can it?) comes to . . . $30,000,000.

Listen less to management talking and check elsewhere EOG-in-Permian.png

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(edited)

1 hour ago, Tootired said:

Sorry, I wouldn’t trust any company that doesn’t present their financial numbers honestly. As an investor I would assume the entire management is dishonest. 

Uh, the ivory tower asshats are the investment companies, who pull targets out of their nether regions, not illumina. 

Edited by footeab@yahoo.com

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3 hours ago, DanilKa said:

Listen less to management talking and check elsewhere EOG-in-Permian.png

Thanks for graph but I don’t quite understand it. Seems cumulative prod for 2017 and 18 should be way higher given higher initial production and slower decline rates. Why is cumulative production so much lower without the graph showing a fall off in daily production? Am I missing something?

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3 hours ago, footeab@yahoo.com said:

Uh, the ivory tower asshats are the investment companies, who pull targets out of their nether regions, not illumina. 

Oh misunderstood. Well if u know better sit tight, doesn’t matter what analyst say in the long run. They r often just following the price action with a bit of lag anyway.

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55 minutes ago, Tootired said:

Thanks for graph but I don’t quite understand it. Seems cumulative prod for 2017 and 18 should be way higher given higher initial production and slower decline rates. Why is cumulative production so much lower without the graph showing a fall off in daily production? Am I missing something?

You looking at log scale for rates on Y and linear cum prod’n on X. Normally I would expect improvement year from year but seems  they’ve stalled in Permian.  My point - average well cum is well below 600K and will never make it there. Your cost estimate is on a lower side, 11-13MM lb fracs cost as fair a bit and there is also cost of acreage, not to mention royalties, taxes, lifting costs, water utilisation, G&A, cost of capital, etc. It’s a tight margins game. 

Its an interactive tableau graph on shaleprofile, you can look by counties etc. 

check comment section there https://shaleprofile.com/2019/09/10/us-update-through-may-2019/

Permian EOG wells only:

?key=1175021056&keepfile=yes&attachment=

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6 hours ago, butasha said:

Danilka, Thanks for the information about the Mike Shellman blog. I am basically a lurker compared to many here but find it surprising that I didn't know about his blog.

Mike Shellman is a smart person who you should probably read.  You may not agree with his views, but he has been in oil biz his entire life and knows his stuff.

https://www.oilystuffblog.com/

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13 hours ago, BillKidd said:

I dunno... maybe it IS only the majors who can make shale work long-term. But I do know they are definitely running out of plays. There just are not that many places to find reserves, easy stuff is gone. If they do NOT make shale plays work and if oil/gas continue to provide the bulk of energy, oil/gas prices will go up a lot. Which tends to cause major economic recessions. It's a big mess this world is in! But then we have renewables on the rise, so, who the heck knows what the future will unfold. As for me, my gut is that renewables are going to capture significant market share sooner than most believe.

 

Renewables (bar hydro) are all intermittent and the cost of grid storage is prohibitively high (even pump storage) so with

very good grid renewables are 20-30% tops which still leaves 70-80% of the problem unsolved.

So we would love coal again in the future or nuclear power.

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22 hours ago, Tootired said:

Over the past few months there have been numerous articles predicting the impending decline of shale production mostly related to profitability. When I looked at EOG however the financials seem to tell a different story, huge cash flow, low debt and very profitable. Are they an exception? Are they an example of shale done right? 

Jason Burack repeatedly will mention EOG as one of the best shale companies per his analysis.  Burack has a background as an oil company and mining company analyst.  However, on recent podcasts, Jason has said that this probably is not the time in the marketplace to invest with EOG.  I own over 100 mineral rights in the Oklahoma SCOOP/STACK, so I keep my ears tuned to the industry.

A company which is probably a wise investment for a long hold in this current marketplace is FNV - Franco-Nevada Corporation.  FNV is a Royalty and Streaming company.  They primarily have interests in precious metals, but they also have holdings in the oil industry, including the SCOOP/STACK.  Their profit per employee is ASTOUNDING!  In 2017, with about 32 employees, the company had 675 million in revenue.  Their revenue inflow has a very high profit margin.

With the coming major, big-time recession, precious metals are a wise bet.

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11 hours ago, Tootired said:

Listen less to management talking and check elsewhere 

I apologize. I probably am incompetent to even comment on this forum, because when I listed the "usual" lifetime expectancy of a spectacular tight oil well, I was tapping into my own experiences, not from either listening to management or checking a graph like the one posted. My properties are scattered throughout the five producing counties in the Bakken--mostly in Mountrail, Williams, Dunn and McKenzie. I also own quite a bit (for me) in the Niobrara and also am intensely involved in the Eaglebine, just up from Eagle Ford. Especially in the core Tier-1 rock in the Bakken, we don't have the porosity of other places, have great pinch-outs in the form of anticlines, enjoy a contiguous reservoir but have very little of this Parent-Child well interaction. In fact, up there, when you run the new laterals and frack, the old depleted parent well frequently becomes better, not worse. In the core, some giant wells are quietly being completed while the Permian gets all the newsprint. The Eaglebine marl is complicated but sandwiched between the Austin Chalk that is shallow and the Buda Shale which is deep--and it is all oil-soaked. So the financial dynamics of what I've experienced may well not apply to other, more typical or studied basins and formations. The Permian is more complicated than the Bakken because in the Bakken you own all layers whereas in Texas, unless it comes in your family inheritance, you buy one layer. I am enamored with Ring Energy for the simple reason that they bought a large position in the San Andrus formation only, send a well bore to 10,000, a lateral to 10,000, frack mildly, use wide spacings, and their wells typically cost only $2M and pay out in 18 months. So I posted something that could be read and interpreted as generic and widespread across all tight oil basins when in reality I was sharing my personal experience. It's probably a bit like going to AA and telling your story, thinking it belongs to everyone. I'll stay the hell off the computer because I'm too old for this and the last thing I want to do is mislead a bunch of people. Thanks, all! I truly have learned a lot here!

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The problems with LTO are inherent in the geology itself, it is ‘tight’. This is low permiability or high resistence to flow. Regardless of who leases this geology, they will not be able to change the characteristics of the rock appreciably. Obviously you can artificially induce permiability by fracturing the rock, but you have not altered the permiability of the rock surrounding the fracture, so a short term gain at best.

Earlier someone indicated that some company has already approached him/her to drill an additional 12 wells on their property next year. This may sound promising, but it is simply the ‘nature of the beast’.

We have all seen, over and over, the signature decline curves of these LTO wells. Reasonable production for about two years, then production declines drastically. For ANY company, whether that is Exxon or Sanford & Son Oil, to maintain a reasonable production plateau - they have to continually drill and frac! The idea of the conventional drilling campaign is out the window.

My point is, whoever owns the lease will simply be leasing the same rock that has defeated those before them. Every outfit has the same access to technology as long as they have the cash to pay for it - whether that cash comes from their own deep pockets or it is borrowed. Everyone mentions the Holy Grail of technology, but I have yet to see anyone post anything concerning this magical new technology.

Finally, the game where companies borrowed money using their ultimate recovery based on the first two years production has run it’s course. Everyone is aware of that scam so money is going to get tight.

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4 hours ago, Douglas Buckland said:

The problems with LTO are inherent in the geology itself, it is ‘tight’. This is low permiability or high resistence to flow. Regardless of who leases this geology, they will not be able to change the characteristics of the rock appreciably. Obviously you can artificially induce permiability by fracturing the rock, but you have not altered the permiability of the rock surrounding the fracture, so a short term gain at best.

Earlier someone indicated that some company has already approached him/her to drill an additional 12 wells on their property next year. This may sound promising, but it is simply the ‘nature of the beast’.

We have all seen, over and over, the signature decline curves of these LTO wells. Reasonable production for about two years, then production declines drastically. For ANY company, whether that is Exxon or Sanford & Son Oil, to maintain a reasonable production plateau - they have to continually drill and frac! The idea of the conventional drilling campaign is out the window.

My point is, whoever owns the lease will simply be leasing the same rock that has defeated those before them. Every outfit has the same access to technology as long as they have the cash to pay for it - whether that cash comes from their own deep pockets or it is borrowed. Everyone mentions the Holy Grail of technology, but I have yet to see anyone post anything concerning this magical new technology.

Finally, the game where companies borrowed money using their ultimate recovery based on the first two years production has run it’s course. Everyone is aware of that scam so money is going to get tight.

While flow rates decline quicker than conventional wells initial production is higher, why is that necessarily bad? If total production and well costs are similar then wouldn’t front loading the production be beneficial to the company? Absolutely it would require a significant amount of effort to maintain production, more so than if they were conventional wells but they were also able to reach much higher levels of production for a smaller cash outlay than conventional wells. Is it just that it’s a different financial model that people can’t get their heads around? . Maybe tight oil companies that r doing poorly and pundits who warn about tight oil finances approach the finances as conventional oil when they shouldn’t? Obviously it works for EOG.

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On 9/21/2019 at 2:53 PM, Gerry Maddoux said:

All the comments above pretty well jive with my limited knowledge but I guess I still trust science to do what it always has done: find a better solution. For example, carbon dioxide injection down the well-bore has been great, as has injection of methane and ethane gas. Chevron and Exxon are all over the Vaca Meurto, which has shale layers twice as thick as the Permian and is over-pressurized doubly too. There's a kid at Texas A&M who has apparently discovered a way to get to almost carbon-neutral. Importantly, when a well gets to end of life, it turns into a salty dog, pulling in water, but at the bottom several of these are rich in lithium. In a perfect world, renewables and hydrocarbons go hand in hand. In a competitive world, it's going to be tougher. In a perfect world, we wouldn't subsidize electric vehicles to the tune of $7500 per vehicle--Henry Ford didn't need governmental subsidies to make his mark. Not to argue, but we're going to improve the way we handle fossil fuels. The gentleman above who said he was waiting for the day the majors took over has a point: Chevron and Exxon have both tried hard to get the EPA to rein in feckless flaring of natural gas, which is nothing more than the release of methane into the atmosphere. Put the methane back down the hole. Wait to hook onto a pipeline. We were more or less pushed into shale because we were told on a daily basis that we were running out of natural gas. I recall back in the eighties when Reagan told the drillers to go for it, and to nudge that along he basically made sure that any NG brought up from deeper than 10,000 feet received a bonus. Elk City, Oklahoma erected a sign, "Natural Gas Capital of the World," or something like that. The Parker Brothers built a rig called Big Bertha that was said to be capable of going 50,000 feet down. It never drilled a hole. The deepest one at that point was one in Beckham County: 29,000 and change. It caved in. There's a transition going on: We now have NG being flared. I don't know. It's going to be interesting to watch. It's true that we're rapidly depleting spacings for Tier-1 rock, that we'll have to move on to the next level, but it's also true that Mr. Berman, for all his many talents, has never been a fan of shale. Wall Street threw money at shale. They're not doing that anymore. In fact, $127 billion in junk bonds start maturing in the next two years. If oil prices don't rise, we're going to see a meltdown in small drillers. But then, unless deepwater goes crazy, or renewables do, or both, we're going to see skyrocketing oil prices. Such is the nature of the energy business. Anyway, this was certainly a thoughtful thread that this "tootired" chap started, and I've enjoyed all the studied comments above. I'm old but still learning and I've certainly learned a lot from all you people. 

Gerry,

 

You may not follow this stuff, but Tesla Subsidies from Federal govt are currently $1875 per car and they end on Dec 31, 2019.

After first 200,000 vehicles are sold (for Tesla this happened in 2018Q3) the subsidy falls from $7500 to $3750(for Tesla on Dec 31, 2018), then to $1875 per car (for Tesla on June 30, 2019), and finally to zero (for Tesla on Dec 31, 2019.)

Flaring if 100% efficient (which it is not) would release zero methane into atmosphere, it is CO2 that would be produced if 100% of the methane were combusted.  I agree higher prices are needed for tight oil to be profitable.  For the average 2018 Permian well breakeven oil price is about $55/bo.  The average EUR per foot of lateral for the average Permian well has been falling since 2016. EUR only seems to be constant from 2016 to 2018 because average lateral length has been increasing, when the average lateral length stabilizes at perhaps 10,000 feet (as in North Dakota Bakken) we will see average new well EUR decrease.

Also note that the average Permian well (with average lateral length currently near 9000 feet) costs about $10 million to drill and frack on average, the $6 million would be the cost of older wells that used one third of the proppant, fewer frack stages and shorter lateral length (about 7500 foot laterals).

Great data on this at www.shaleprofile.com

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If it wasnt for US shale , this wouldnt be happening

 

__________________________

 

McKinsey: US to source 50% of new gas through 2035

In the last 12 months, a record volume of LNG projects took final investment decision. These totaled more than 80 million tonnes/year of new production, or 25% of the current market, according to an outlook by McKinsey & Co.

 

In the last 12 months, a record volume of LNG projects reached final investment decision. These totaled more than 80 million tonnes/year of new production, or 25% of the current market, according to an outlook by McKinsey & Co.

According to the report, “Global Gas & LNG Outlook to 2035: H1 2019,” more than half of global natural gas supply growth until 2035 will be sourced from the US: 380 billion cu m (bcm) out of 635 bcm.

McKinsey’s report, released in September as part of its Energy Insights series, went on to note that China, South Asia, and Southeast Asia will account for 95% of global LNG demand growth through at least 2035. More than 100 LNG liquefaction projects totaling 1,100 million tpy are competing to fill a 125 million-tpy supply shortfall projected over that period. Only 1 in 10 of these will be competitive enough to reach FID, the consultancy said.

“We see abundance of supply, going forward,” McKinsey partner Dumitru Dediu told Oil & Gas Journal at Gastech 2019 in Houston. “We also see Qatar making progress towards FID. Demand continues to grow, but supply is likely to grow even faster. This creates a very difficult situation for suppliers trying to secure demand [in advance of FID].”

Dediu continued, “We don’t see the becoming easier, especially for single-source suppliers. The ones who will actually benefit most will be portfolio players, who can absorb the volumes while taking on and managing the risk.” LNG producers “can only find certainty in projects which can deliver into Asia at below $7/MMbtu,” he said.

Dediu divides LNG importing countries with potential interest in floating regasification into two categories: those replacing or supplementing their own production with LNG (Thailand, Pakistan) and therefore already having the support infrastructure in place and those where grid and other development is still needed. In the latter case, many opt for a direct gas-to-power option with the power then delivered through the electrical grid. Others, such as Brazil, position regasification near an already active industrial site and use the gas there. Either of these options requires engaging a broader spectrum of stakeholders than do new sales into more established LNG buyers.

On the liquefaction side, Dediu expects the modularization of processes undertaken for the Prelude floating LNG project offshore Australia to continue being adapted for both floating and land-based developments, citing nearshore gravity-based Arctic LNG 2 and Coral LNG prime examples. “Going forward, many of the pure floating solutions will be relatively expensive” leading to a mix of floating, nearshore, and gravity-based approaches made possible by the increased modularization.

 

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On 9/22/2019 at 10:54 AM, Gerry Maddoux said:

In fact, up there, when you run the new laterals and frack, the old depleted parent well frequently becomes better, not worse.

Could you comment more on this? I am very interested in these beneficial parent-child relationships. I've only recently been more involved in the production side of things and I have heard about these kind of beneficial relationships between the Austin Chalk and Eagleford, but I haven't seen much success in the projects I've been involved with down there so far. To be fair, I work up north in the Permian most of the time, so I'm less familiar with those reservoirs. 

Perhaps it would be better to start another thread, but I think this still falls in the ballpark of determining profitability of these wells. 

 

Edit: specifically, I have seen offset wells produce a lot more after fracking a nearby well, mostly as result of charging the reservoir I assume.

However, i read a study (I'll try to find it and post it later) that suggested fracking wells in the Austin chalk followed by a closely spaced well in the Eagle ford could cause some beneficial communication between wells. I have yet to see it in practice though.

Edited by PE Scott

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https://seekingalpha.com/amp/article/4293009-drill-baby-drill-closer-look-us-onshore-drilling-productivity

 

The amount of drilled wells has dropped per month but the amount of completions are up signaling more production to come in the near term. Finally a decent post showing a little history of drilling vrs completions.

The big drop off after a well is completed is not compared to a well in the Permian before 2014 often. That was around the time many technical innovations really ramped up and have been gaining ever since. Now there is far more production with far fewer oil workers and drilling crews. This is a far different story from the narrative of a declining well.

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On 9/21/2019 at 1:21 PM, BillKidd said:

Art Berman is a consulting geologist that has been saying for years that shale plays are NOT making money and it can be proved by analyzing the operator's required SEC financial reports. Now, such analysis takes expertise to do it properly. He's written many papers, made many speeches, does regular blog reports and videos. He has long touted EOG as about as good as it gets. EOG has good rock. They also did not pay huge, crazy high sums of money for their leases.

As for a comment above inferring that companies would not be drilling if it were not profitable, that seems like a proper way to look at it but it's actually hugely flawed thinking. The reason why is because the oil business is nothing like it was prior to shale. Now, it's all very large companies, most multi-billion companies, and they have all been infused with humongous amounts of capital because Wall Street felt they had nowhere to go to get a decent return in an economy based on stimulus and ZIRP. Operators tooted their horn about how great their wells are and capital markets bought into it and it's just crazy how much money has been thrown at shale. So, when you get x-billion dollars to spend on drilling, you drill. Even if it's not profitable. Because you have contracts. That make you drill. This has been a huge stumbling block to get people to realize. Yes, there are good spots, but the MAJORITY of shale rock is not profitable. Overall... has it worked? You can't just count the great 10% to 20% of a play that's good and not count all of those crappy wells you drilled to find the core.

Art Berman also points out the fact that these companies 'pencil whip' the public via their presentations, not counting all of their 'all in' expenses. Without a doubt, some of these companies have bordered on fraud with pie-in-the-sky presentations about how profitable their wells are. Believe it... companies do not 'fully tell the truth.' They leave out a lot. Always tooting their horns about how great everything is! You gotta dig for truth.

I dunno... maybe it IS only the majors who can make shale work long-term. But I do know they are definitely running out of plays. There just are not that many places to find reserves, easy stuff is gone. If they do NOT make shale plays work and if oil/gas continue to provide the bulk of energy, oil/gas prices will go up a lot. Which tends to cause major economic recessions. It's a big mess this world is in! But then we have renewables on the rise, so, who the heck knows what the future will unfold. As for me, my gut is that renewables are going to capture significant market share sooner than most believe.

Lastly, a biggie for shale wells is how fast to payout, because the decline is steep. If they can pay out in less than one year, that is fantastic. Two years is still terrific. But most do not!

Are you only looking at the oil running out? Will much of the natural gas still be recoverable when the oil is mainly gone? 

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10 hours ago, ronwagn said:

Are you only looking at the oil running out? Will much of the natural gas still be recoverable when the oil is mainly gone? 

There are millions upon millions of acres of gas-productive rock that would be economic if prices were to quadruple. Just in the USA... Texas, Oklahoma, Pennsylvania, West Virginia, Ohio. The Permian, Eagle Ford, Haynesville, Marcellus, Utica, Anadarko/Stack/Scoop. And then there's Canada and Mexico and that's just the western hemisphere. Whether or not that will ever happen is anyone's guess. Renewable are what scares me the most. I fear a technological announcement, which could happen any day, that is a game changer for renewables, and which will result in stranded gas assets due to falling demand. Technology advances SO fast these days.

Regarding natural gas, it's interesting that Aubrey McClendon, the late CEO of Chesapeake, and also T. Boone Pickens, the late CEO of Mesa Petroleum, both spearheaded MAJOR pushes for natural gas as a transportation fuel. It's cleaner. That really went nowhere. We now have some expanded use within the trucking industry, but it's mostly short hauls.

If renewables do NOT make major headway in the next, say, 40 years, I would think natural gas would increase its share. Once again, it's price.

Personally, the other huge risk, seems to me, is a horrific economic meltdown, decreasing demand for a decade or so. The credit experiment, global in scope, could implode and the world has never 'been here before,' so just how bad it would be is an unknown. Good luck to us all!

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  • Thank you Aubrey! Sounds like a very realistic viewpoint. I followed Chesapeake, Pickens, and all the other proponents. 

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Oxy just hit a sweet spot in Lea County: IP over 5,000 blls/day, heavily pressurized. 

The seismic, gps drilling and completion techniques have jumped the rails. 

Vickie Hollub is also pushing carbon neutral. The boom is in full force, which is also driving down the price of oil. 

It is difficult to get oil out of hard rock! But it’s getting easier. 

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