Forbes: Maybe BHP Billiton's $20B Fracking Bet Wasn't A Blunder After All
He insists that he’s doing just that. Shale operations have ramped up to account for 40% of BHP Billiton Petroleum’s 670,000 barrels per day of oil (and equivalent gas) production. The focus of their efforts is clearly the Eagle Ford shale, where Skaufel says their position is “the best of the best.” Of 25 total rigs in operation, he has 17 of them in the Eagle Ford. The next most exciting area is the Permian basin, which has seen a riot of new activity in the past two years, and where BHP has 450,000 acres. Even the gassy Haynesville shale of Louisiana is “economically robust” now; with the trebling of gas prices in two years BHP is generating 35% returns on invested capital there. Fayetteville, however, remains a dud. It holds bounteous amounts of dry gas — but even at current prices the costs of getting it out can’t compete with other options. At the right price — he won’t say how much — “there’s an abundance of gas.”
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Replies to This Discussion
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Permalink Reply by 1kw6x71km1v37 on
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Perhaps all that will offset the apparent bum leaseholds BHP acquired from from Halcon and Anadarko in Vernon Parish.
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Permalink Reply by Joe Aldridge on
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CS,
I must have missed something. What bum leases in Vernon are you referring to?
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Joe,
BHP bought some leases from Anadarko and Petrohawk a while back in Vernon Parish. They drilled a well west of Neame near Anacoco Creek that went dry in 10 months. They folded up and moved out. Since then no permits have been issued to drill in the Pinewood Field that I have seen. Whether the leases have future utility remains to be seen. The Forestar Mineral #1 produced 21 barrels of oil in March, and two drilling permits were allowed to expire. I don't actually know if Billiton held the leases for the Forestar well, but Anadarko (in partnership with Petrohawk) was the only company I ever heard of that did any leasing in the Pinewood Field for this play. If you move just a little to the northwest, up in the Burr Ferry Field is where the good wells are. It's odd how the deposition/recovery varies from place to place.
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Permalink Reply by Skip Peel - Mineral Consultant on -
cheap, suggest you consider starting a Vernon Parish Group page since you appear to be the most active member with an interest in that area. You might want to start with this:
http://sonlite.dnr.state.la.us/sundown/cart_prod/cart_con_wellinfo2...
EOG always gets my interest. Long before they were widely known for the foresight to switch from NG to liquids they were one of the top three horizontal drilling companies in the nation behind only CHK and DVN. When I would mention them six years ago members had no knowledge of them. They ceased to fly under the radar long ago and now most everyone recognizes them as the most successful mid-major E&P company. A Vernon Parish Wildcat (INDIGO 25 H #1) will be worth following.
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Permalink Reply by w.r. frank on
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This is typical Forbes BS. NG at its recent low was $1.90/mmbtu. A treble would be $5.70. It is robust returns if you say lease bonus, minimum volume commitments for gathering and treating and transportation, etc. are "sunk costs" as CHK now says. Oh well, it was just cash money out the door.
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Permalink Reply by W. Marshall Shaw on
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Back in the 1920s, my grandfather drilled some wells in the chalk formations of Vernon and Sabine Parishes. The wells gushed and flared dramatically, but they didn't last very long. There is still some question about whether my family and I still have interests there -- I don't think that we do -- but the point is that there can be a lot of smoke (!!!) and mirrors when it comes to chalk. But it is interesting to keep up with the comments on this board.
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Permalink Reply by Two Dogs, Pirate on
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The EOG/Indigo 25 H #1 well is a TMS. The original well was going to be about 10 miles to the Southwest of this one.
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Permalink Reply by Joe Aldridge on
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CS,
GHS would not let me reply to your comment. So I'm posting to the general thread.
I was aware that APC let the permits expire and it looks like they are going to let another two go. I was not aware that BHP had gotten involved in that area. Interesting. You are so correct in how two areas in the same formation can be so different. The question in my mind is: Is it truly formation difference or is it the difference in drilling protocol between the areas? Do you know if APC ever got any offers on the acreage they had for sale? Its no longer listed as far as I can see. Also, recently Pryme sold out everything (they held 5%) they had for 6 million or so to cover their debt to an undisclosed buyer. That may have been a steal for someone.
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Joe,
At times, the problem appears with the Austin Chalk formation, i.e., limited fractures downhole. Or with the formation collapsing in on the laterals. The slotted liner, unavailable in the late 1990's, was supposed to offer some relief, but you don't hear much about that technique today.
Then there are incompetent horizontal drillers screwing up the pooch.
It's hard to pin the tail on any particular donkey, but you get a little of all those problems in one well, and I figure those are the "dry holes."
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Permalink Reply by Joe Aldridge on
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CS,
I agree. The problems are multiple. The AC is different. It's not a sand or a shale formation and it seems like most industry people don't understand that.
I'm in the AC window on the East side of the River and I'm concerned about leasing to the wrong operator. Of all companies out there I would have thought that APC would have been the company that could have made some good wells. But when I went to that first pre-app hearing and they talked about 8,000 ft laterals I was afraid they were headed in the wrong direction. So at this point I have not figured out how to find an operator that knows what the chalk is about. If you have any ideas I'm listening.
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Don't lose sight of the fact APC's ulterior motive in developing the Austin Chalk in west Louisiana was to hold the acreage for future TMS development. Whether that bet proves out remains to be seen.
Another aspect of the AC was the wells paid out fairly quickly, sometimes in as little as three-six months. Pool half a dozen of these together, and you have the equivalent of one good well, cost free, after minimal operating expenses.
Joe, I don't know who stands today as the premier horizontal drilling operator, but back in the day of the Masters Creek play, Nabors was clearly the most competent driller of the AC, albeit Nabors was a contract driller and not an operator. They may be able to recommend.
I would stay far away from anybody who thinks in terms of extra long laterals, unless the state of horizontal slotted liner technology can now justify it.
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Permalink Reply by Joe Aldridge on
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The long laterals were a concern to me when APC made the presentation at that first pre-app conference across the River.
So would you try to write a lease that does not allow laterals over 5,000 ft.? And what company would allow that clause in a lease? We are currently having problems with companies rejecting leases in the TMS that contain no surface rights on small tracts - 5 to 10 acres. So it gets difficult to try to work with people that will not be reasonable. So I can't see where something like a < 5,000 ft clause would be acceptable with most companies.
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