[ROCKMAN]

DC - Difficult to predict future costs using histories for the last 5 to 7 years. First, more recent wells have much longer laterals and mucho frac stages. But that also means fewer wells per acreage positions. Prices could be normalized on a footage basis. But then you need to see 4 or 5 years production history to normalize results.

One of the big savings factor has been a very big reduction in drill time. But such gains on that order can be made in the future. As you know there are physical limits. Fast mob/multipad drilling saves some money but those are in place now. Not much more improvement possible IMHO.

And then there's the learning curve with respect to sweet/sour spots. And that varies from company to company as well as variations in the potential variations in one company's acreage and anothers. And lastly not all companies do the job as good as others.

Very tough task indeed.

[Oily Stuff]

DC, I understand NPV very well, I simply fail to see it's significance in tight oil economic discussions. My bad, I suppose, as I am old school and when I make a decision to drill or not to drill a well it is based on well costs, risk, estimated time to pay the well back, product prices and ultimate estimated return on investment over the life of the well. The net present value of an income stream is only relevant to me if I am selling production, or buying someone else's income stream. I am not a public company, it is not necessary for me to impress others, or myself with reserve studies; for lack of a better description my business plan has always been to hold on to every barrel of production I find like my life depended on it. Since I started just north of standard derricks, oil prices are up nearly 1200%.

Having said that, I guess NPV is important to folks having to wait 4 years to get their money back on development costs. I always like to get my money back in less than 18 months. Four years to pay out, with 25-30% annual decline rates and I would have died at an early age from stress. Or become a horse shoer.

To understand how tight oil sources will play out relative to our energy future in America that facet of my industry, clearly different than mine, needs to tell the truth, to not hide the important details in corporate statements. I do not believe that it is telling the complete truth. Are these well profitable enough for Americans to count on 40,000 well bores and 5 million barrels per day? I personally do not think so. There endenth my rant for the day.

Your 10 year EUR's are very similar to my guesses via DI data in the EF sweet spots. Outside the carpet bombing that the bigger companies do in what they believe are sweet spots (hard to tell sorting thru 19 wells in one unit exactly how sweet), in the not so sweet spots, less EUR and many, many wells in the EF, will not pay back costs.

If I may: I think the LLS to WTI premium thing is about gone for the EF, plus/minus 3-5 bucks over WTI, no more 15-18 dollars, regardless of volume, IMO. We are saturated with crude oil along the GC at the moment and that's only going to get worse. I cannot even term up my oil at the moment because the market is so volatile. So going forward I would count on WTI prices and that's about it. I think the net price per barrel those tight oil guys make, after this and that, is 65 dollars. What I cannot discount from that is the cost of borrowed money. Would it not be considerable?

And lastly, if I may, let us not assume that drilling costs are going to go down, on average, in any tight oil play simply because Leo says they will. Where is the data to substantiate that? I won't go into that but it astounds me that anyone can say that costs will go down, in anything, over the next 5 years. That would be the first time for me. My costs, for instance, since my first well 40 years ago, are up over 400%. Year to year they have never gone down. Lower well costs is faith based optimism, I guess hoping for more technological break thru and/or making the mistake of listening to CEO's on CNBC and believing them. When I have the time, and care, which I don't either, I cannot AFE those EF wells, with average lateral lengths and average frac stages, at anything less than 7 million dollars. Maybe they can whack off a few days of rig time, and moving costs, by sliding a rig around on the same pad, big deal. A week of reaming and lost circulation, a stuck BHA and not so average well costs are above 8, easy.

Now lastly, promise, I don't think well costs are going to go down because I think the water situation in S. Texas has reached critical mass. I hear Lessors are now fussin' about water, big time, and are thru watching the ESP's in their Carrizo wells need to be lowered every month and the TDS of that water go up, up, up. Some of these shale dudes are trucking 150,000 BW for frac'ing, 50 miles or more. Figure 50 cents a barrel, plus 4 hours of trucking at 120 an hour, 160 BW per truck, that's 4.00 a barrel, there abouts. We are in the worse drought in history in Texas, prolonged and very, very severe. My prediction is that rig counts will go down in the EF soon because of the W word.

It would be a mistake to assume anything associated with drilling these shale wells is going to go down. Product prices will go down, not costs.

So, 212,000 BO x 60 dollars a barrel, net = 12.5 million dollars and they have spent 7- 8 million to get that. Sorry, that's ugly.

But God bless 'em.

[TheServant]

DC,

First, thank you for responding to my earlier post. I figured 4000-9000 wells/yr in the Bakken was wildly optimistic, but thought I would throw it out there since it is apparently feasible (at least in TX) given data from the 2 TX tight oil plays.

This calls to question how long this kind of drilling can be maintained in the Texas plays. If I am eyeballing your first model on Eagle Ford, it looks like it has about 3000 cumulative wells drilled by mid 2013. If the previous article I linked is accurate and 4000 or so wells have been drilled in the past 4 quarters alone, it seems to be running well ahead of this first estimate. Perhaps active drilling in this play will wrap up before 2020 instead. Hard to say.

Still trying to envision where those rigs will go in several years once room for new wells begins to run out in the TX plays. I find your modeling interesting. Certainly a difficult task given all the variables involved. Thx.

Dave

[ROCKMAN]

OS - I agree with you about the unlikely decrease in cost. Maybe a bit for $'s per foot. But the shales will prove to be very valuable...for the US consumers. They don't need to be concerned about NPV, ROR or payout time. The shales are adding to domestic production. If not reducing prices much at least reducing our trade balance. A great wealth transfer to mineral owners, service companies and state tax collectors. Management and staff ain't doing to shabby either.

But someone loses: shareholders. And while it may just be me being politically incorrect again, I'm not going to lose much sleep worrying about them. You pays your money and takes your chances. Not much different than blowing your wad in Vegas. I've seen too many folks their money at stock with no idea of what they were doing. Just succombing to greed.

Always going to be winners and losers. The mineral owners, the state revenuers, the hands, the consumers and the govt trade balance wins. I can live with it. LOL

[Oily Stuff]

RM, exactly: shareholder equity will ultimately suffer when the drilling treadmill can no longer be sustained. When the drilling stops things will go not down the hill, but virtually over the cliff.

I do not believe personally that even the biggest of tight oil players can do what they say they can do without continuing to borrow enormous amounts of money. My question would be, what is, what will the total indebtedness of public, tight oil companies ultimately be and are they servicing that debt in such a manner that when they can no longer grow, or sustain production income streams will that debt be paid. Or will lending institutions that loaned the money be hung out to dry and need to be bailed out...by us? Far fetched? Maybe. Maybe not. CHK has been selling other tight oil assets to reduce their debt liability, what happens when those tight oil assets are actually plugging liabilities, production income is screaming down at the speed of sound and there are no more willing buyers? As we both know a dry hole, or a well that is depleted can't then be sold like a cow, or a duplex. When it's gone, brother its gone, right?

[ROCKMAN]

OS - I worry even less about the bankers then the shareholders. LOL. Really. If the path follows past meltdowns, like in the early 80's, the public won't likely be bailing any of them out. Perhaps I've dealt with bankers more than you and seen how good they are at covering their butts. Take CHK. No matter how bad they implode I doubt they'll ever go bankrupt or dissolve. Typically when it gets that bad someone, like ExxonMobil, will take them over and assume the debt in the process. The hit will fall on the shareholders. Like all booming stock plays the trick is to know when to bail. Doesn't matter if it's homebuilders, dotcoms or shale players: buy low...sell high...and for Dog's sake don't get greedy and hang in there too long.

I've worked for some small pubcos and have watched it up close and personal. For the most part it really is a rigged game. I've told the story about pissing away $18 million to drill hz wells that, while increasing production rate greatly, didn't add $1 of new reserves. And the stock boomed. And eventually the last shareholders got slaughtered when the company filed bankruptcy and was taken over by another pubco. The last hanger-ons got about $0.05 for stock that had topped out over $5/share. One silver lining: the biggest hit was taken by a Wall Street raider that did a hostile take over of the company. Some just Karma there. LOL. But all the facts were there in the annual report if they took the time to read it. But they didn't: they just greedily swallowed the Kool-Aid the brokers fed them. A travesty but completely legal. I just hope I can finish out my career by not working for any publco.

[rockdoc123]

$this->bbcode_second_pass_quote('', 'I') do not believe personally that even the biggest of tight oil players can do what they say they can do without continuing to borrow enormous amounts of money. My question would be, what is, what will the total indebtedness of public, tight oil companies ultimately be and are they servicing that debt in such a manner that when they can no longer grow, or sustain production income streams will that debt be paid. Or will lending institutions that loaned the money be hung out to dry and need to be bailed out...by us? Far fetched? Maybe. Maybe not. CHK has been selling other tight oil assets to reduce their debt liability, what happens when those tight oil assets are actually plugging liabilities, production income is screaming down at the speed of sound and there are no more willing buyers? As we both know a dry hole, or a well that is depleted can't then be sold like a cow, or a duplex. When it's gone, brother its gone, right?

[Oily Stuff]

Rockdoc, I appreciate your consistent and passionate defense of the tight oil, public companies. You live and work in that world, I don't. I never did and like RM, I don't intend to, ever.

The ability to fund an aggressive drilling campaign can be partially funded by liquidating unwanted acreage positions as long as there are willing buyers with their own borrowed money available to acquire that acreage. As the bloom falls off the shale bushes that is less likely to occur. In my part of the S. Texas EF play tens of thousands of acres leased 3 years ago is simply going to be released. Dropped, not perpetuated. BHP has written down vast amounts of their acreage position from Petrohawk; the American tax payer took the hickey on that. Folks who bought CHK acreage in the Utica probably can't give it away now, or in the Marcellus NFZ ( no frac'ing zone); lets ask Rex how he feels about his shale acquisitions. There will be less of that sort of inner breeding, IMO. Besides, how are those big guys going to stay on the drilling treadmill if they are selling acreage?

If the plan is to not drill so aggressively going forward that is contrary to the 40,000 well, 5 million BOPD, energy independence plan I hear ever day from fellas like Leo and I am a tad bit confused by that part of your statement. They may believe in hyperbolic decline rates with long fat tails but that does not mean that's what they will get. The "reservoir" they drain is only as big as the frac radius they create. If we went on the hunt for fractured AC wells drilled in the 80's that produced 20 years we would be hunting a long time. We'd find a few that lasted 10 years, but not many. I am kind of a fan of Webble Telescopes work over at TOD; if these wells can produce at stripper well levels, which I doubt, the incremental lift costs per barrel are going to be astronomical. $50,000 dollar rod jobs don't work too well on 8 BOPD wells.

This seems timely to my previous post regarding debt: http://www.theoildrum.com/node/10139#more

Lastly, I know you think I am dumb but actually I don't believe that CEO's use embellished, partially omitted or somewhat altered statements about their companies tight oil performance for their own personal stock gain. I think they have a fiduciary responsibility to their shareholders to keep a happy face. And to their lenders. And the prettier the picture they paint the more likely they are to be able to keep the little hamster wheel turning.

RM is legitimately concerned for shareholder equity; me too. You are absolutely correct also, shareholders have the ability to bail. The best I can hope for is that they know when to bail. Its part of the reason this debate regarding truth in tight oil advertising needs to continue.

[rockdoc123]

$this->bbcode_second_pass_quote('', 'I')f the plan is to not drill so aggressively going forward that is contrary to the 40,000 well, 5 million BOPD, energy independence plan I hear ever day from fellas like Leo and I am a tad bit confused by that part of your statement.

[Graeme]

How do posters in this thread respond to this then?

Trouble in fracking paradise

$this->bbcode_second_pass_quote('', 'T')he shale revolution is “a little bit overhyped,” Shell CEO Peter Voser said last week as his company announced a $2.1 billion write-down, mostly owing to the poor performance of its fracking adventures in U.S. “liquids-rich shales.” Which of its shale properties have underperformed, Shell didn’t say, but CFO Simon Henry admitted that “the production curve is less positive than we originally expected.”

Shell was a latecomer to the tight oil game. As late as 2010 it was acquiring mineral rights at inflated prices, predicting that those properties would produce 250,000 barrels per day in five years. Three years down the road, they are yielding only 50,000 barrels per day, and the company intends to sell half of its shale gas and tight oil portfolio. Shell has officially abandoned its production target of 4 million barrels per day by 2012-2018. Instead, Voser said, “we are targeting financial performance.”

Second-quarter earnings were dismal for the so-called oil supermajors. Shell, BP, Exxon Mobil, Chevron, Total SA, Statoil, and Eni SpA all reported sharply lower profits.

Production was also down nearly across the board, with only Total SA reporting an increase.

Of course, none of this would be a surprise for those who read my article from March, “Oil majors are whistling past the graveyard.”

The declining profitability and production primarily owed to lower oil prices and rising costs. As Platts reported in June, total capital spending for the top 100 U.S. producers in 2012 rose 18 percent year on year. Costs will be higher still this year.

Rising costs are partly due to the tight oil boom itself. Producers that invested heavily in tight oil production are struggling to maintain output against the accumulating undertow of existing wells, where output declines rapidly. Geologist David Hughes finds an average decline rate of 60 percent to 70 percent for the first year of production in new wells in the Bakken shale of North Dakota. And a new statistical analysis by Rune Likvern at The Oil Drum shows production from most Bakken wells falls by 40 percent to 65 percent in the second year.

[rockdoc123]

$this->bbcode_second_pass_quote('', 'H')ow do posters in this thread respond to this then?

[dcoyne78]

$this->bbcode_second_pass_quote('Oily Stuff', '
')...And lastly, if I may, let us not assume that drilling costs are going to go down, on average, in any tight oil play simply because Leo says they will. Where is the data to substantiate that?
...
EF wells, with average lateral lengths and average frac stages, at anything less than 7 million dollars. Maybe they can whack off a few days of rig time, and moving costs, by sliding a rig around on the same pad, big deal. A week of reaming and lost circulation, a stuck BHA and not so average well costs are above 8, easy.

[ROCKMAN]

DC - As far as the Austin Chalk goes there was very little effort to focus on sweet spots in much of the trend. Virtually every legal location in the heart of the play was drilled. But like every fracture play individual well results were dependent on how many natural fractures it cut and how many were hit by the franc job. Of course, like every trend it had its limits and eventually terminated for the most part. But during the height of the crazy times Chalk deals weren't pitched on the basis of a geologist's map but on the basis of a lease map. Basically if you had a lease you drilled well.

[dcoyne78]

$this->bbcode_second_pass_quote('TheServant', 'D')C,

First, thank you for responding to my earlier post. I figured 4000-9000 wells/yr in the Bakken was wildly optimistic, but thought I would throw it out there since it is apparently feasible (at least in TX) given data from the 2 TX tight oil plays.

This calls to question how long this kind of drilling can be maintained in the Texas plays. If I am eyeballing your first model on Eagle Ford, it looks like it has about 3000 cumulative wells drilled by mid 2013. If the previous article I linked is accurate and 4000 or so wells have been drilled in the past 4 quarters alone, it seems to be running well ahead of this first estimate. Perhaps active drilling in this play will wrap up before 2020 instead. Hard to say.

Still trying to envision where those rigs will go in several years once room for new wells begins to run out in the TX plays. I find your modeling interesting. Certainly a difficult task given all the variables involved. Thx.

Dave

[ROCKMAN]

DC - These should be some fairly accurate numbers from DrillingInfo that draws of the TRRC public data base. To avoid confusion these deal with only wells that began producing between June 2012 and May 2013. Of the 869 wells 293 were classified as NG and 576 as oil wells. Of course the NG wells yield a good bit of oil also. When I get a moment I'll break it down to the last 3 and 6 months.

[ROCKMAN]

DC - Forget those numbers. Search engine screwed up. Double checked:

Last 12 months: 1439 oil. 249 NG
Last 6 months: 828 oil. 118 NG

[TheServant]

Thanks DC and RM.

That gives me a much better idea of the activity ongoing in TX and what might be the future activity in ND (& clears up my surprise after reading the article referencing the Baker-Hughes #s). Didn't realize the Permian Basin wells were primarily vertical. That makes much more sense.

[ROCKMAN]

TS - I don't have the numbers handy but there has been a good bit of hz drilling in the Permian but a lot of the gains have been from CO2 injection projects. New wells were often shallow vertical wells.

[dcoyne78]

$this->bbcode_second_pass_quote('ROCKMAN', 'D')C - Forget those numbers. Search engine screwed up. Double checked:

Last 12 months: 1439 oil. 249 NG
Last 6 months: 828 oil. 118 NG

[ROCKMAN]

DC - I'll see what I can pull up for the Spraberry.

Yes...all EFS and all hz. Those numbers are for wells actually put on production in the stated time frames. Much more meaningful then rig counts and permit numbers. These are the real deal and not projections. Of course the rate of new wells coming on in the future may be less. Just talking to a vendor Friday who does a lot of work in
the EFS and he ran down a long list of operators that were releasing a lot of rigs. But it will probably take as least 6 months for such a slow up to be seen in new wells starting to produce.