Replies to This Discussion

Permalink Reply by Skip Peel - Mineral Consultant on April 25, 2013 at 11:49

W-B is too small to be competitive with SWN or any other mid-major or major energy company.  Why do you think it took them 3 years to build a pipeline to the well?  The answer is they do not have the financial ability to develop what they found?  I don't think they sat around for those three years.  I think they went out and tried to sell a larger company capable of the required level of investment on the prospects of the Brown Dense.  It is quite common in the industry for smaller companies to develop prospects and then sell them.  Some are small, local operators that stumble upon something in their back yard like Weiser-Brown.  Others have a business model that has them finding a geological prospect, establishing an initial lease block and then doing a sales job on the operating companies in their circle or going to a "prospect expo" where operating companies attend looking for development opportunities. I think SWN knows everything about the Brown Dense that W-B knows.

Permalink Reply by Land Rat on April 25, 2013 at 12:23

My guess is that WB reviewed some 2D, saw something anomalous, leased from Exxon (maybe even signing a CA on well science) and got lucky. If anything, they would be sharing that information with XTO, not SWN.  Heck, XTO could have even paid them to drill the well just to maintain an expiring servitude. 

As far as the length of time between spud and pipe?  Look at what the louisiana light spot price was in 2009...and what was going on as far as lliquidity, investment, etc.  They're getting 2-3x the revenue they would have received had the put that well online when it was drilled and they have a lot more confidence in the future of the world energy marketplace. Why would they have even given it a try if they couldn't afford to put pipe in for another 4 years.

I don't know what SWN's leasehold position looks like on a map, but to me it seems like, as you have said, they had very little well control to stake a huge resource play on and opted to establish themselves in areas where there has been historic conventional production, Arkansas, etc...possibly because of how prolific this one well was when viewed superficially, which may prove to have been the wrong move (in regards to getting the "best" spot) as evidenced by their all but condemned northern acreage.  I just think that if they had the information back then, their lease position would have focused more around the well and not so far west and north.

Permalink Reply by John D Cook on April 25, 2013 at 12:34

I agree Skip, could not have been better said. Hard for small company to raise funds to develop something like W-B encountered.  They never dreamed they would have this barnburner well.

Permalink Reply by Skip Peel - Mineral Consultant on April 25, 2013 at 13:23

If W-B shared it's BD find with XTO then XTO/XOM must not think much of it based on their actions to date.  From what I have heard this is Exxon fee land.  If that is correct, there is no need to drill it to maintain a lease.  I also discount the spot price as a reason to delay a pipeline.  I think that the decision to invest in a pipeline has more to do with the number of potential well locations and an operator's ability to fund the drilling and completion of those wells. 

Permalink Reply by Land Rat on April 26, 2013 at 0:37

No, but there may be a need to drill to maintain a servitude as was the case with the XTO well in Morehouse Parish.  I wasn't citing spot price as the reason, just using it to illustrate the precipitous decline in energy prices and the general non-availability of capital and bullish thinking  that unfortunately coincided with the spudding of this well as the economy tanked. 

As far as what XTO thinks of the lower smackover in their acreage, who knows?  But, there are some very fundamental differences between XTO and SWN.  First, XTO does not need to grab land, they already hold fresh servitudes over hundreds of thousands of old timberland, and, second, they don't need to appease their shareholders with a new flagship resource asset every several years.  They can just sit back and wait.  Being in the current SWN units ought to provide them with tons of free information as well. 

Permalink Reply by pip318 on April 27, 2013 at 1:05

I wonder if SWN paid BW to sit on the well for 3 years while they put together their leases.  BW starts producing the well at the same time SWN is producing theirs--the information is becoming public in parallel.

Permalink Reply by Skip Peel - Mineral Consultant on April 27, 2013 at 1:22

Very well could be, pip.  However keep in mind that building out infrastructure is a large capital consideration when a prospect appears to be a resource play.  One far beyond the means of a company such as W-B.  It is usual for a company of W-B's size to promote the prospect to companies with the financial ability to fund the exploration and infrastructure for what could turn out to be a quite large area.  There would be terms of the deal to benefit W-B of course but any meaningful pay day likely depends on SWN unlocking the mysteries of the BD and proving up a large number of potential well locations.  Neither of which has occurred to date.

Permalink Reply by Bubba on April 30, 2013 at 9:46

Skip,

Respectfully I disagree that this play is beyond the means of a company like Weiser. I have seen their AFE for an offset to the Exxon-Mobile #2 and at $2.7 million drilled and completed (without frac) this is a typical type of well that hundreds of independents can drill along with partners. Even though the #2 well is exhibiting a typical steep decline from a tight formation, the economics of this as a vertical play may be superb. I don't know why it took three years to get the pipeline in place other than the longstanding rumors that someone wanted that delay, especially in light of the minimal cost of probably less than a half a million. Typically, the working interest partners want a little production history before venturing out and I expect that to happen soon. 

Permalink Reply by Skip Peel - Mineral Consultant on April 30, 2013 at 11:40

Bubba,  no reply button below your reply so I'll try to get this close.  I feel sure you'll find it wherever it ends up.  LOL!  It's certainly okay to respectively disagree especially when you provide reasons for why your opinion is different from mine.  You did that just fine.

Please understand that I am not slighting W-B.  If the Brown Dense can be developed in that location by vertical wells I would consider W-B capable.  They might need a little investment assistance but I think they are a capable vertical developer.  If vertical wells have sufficiently long life they could be economic.  The jury is out on the Exxon-Mobil #2 until there is more production history.  However if W-B is considering an off set, then the Brown Dense may be a conventional reservoir, at least in that specific locale.  SWN has described the Brown Dense as an unconventional reservoir.  An unconventional reservoir requires horizontal development and extensive infrastructure investment both of which are beyond W-B's abilities.  It is one or the other, it can not be both in the same location. 

Here are definitions from the Schulumberger Oilfield Glossary to illustrate my point.

unconventional resource

English | Español

1. n. [Shale Gas]

An umbrella term for oil and natural gas that is produced by means that do not meet the criteria for conventional production. What has qualified as unconventional at any particular time is a complex function of resource characteristics, the available exploration and production technologies, the economic environment, and the scale, frequency and duration of production from the resource. Perceptions of these factors inevitably change over time and often differ among users of the term. At present, the term is used in reference to oil and gas resources whose porosity, permeability, fluid trapping mechanism, or other characteristics differ from conventional sandstone and carbonate reservoirs. Coalbed methane, gas hydrates, shale gas, fractured reservoirs, and tight gas sands are considered unconventional resources.

conventional reservoir

1. n. [Shale Gas, Geology] A reservoir in which buoyant forces keep hydrocarbons in place below a sealing caprock. Reservoir and fluid characteristics of conventional reservoirs typically permit oil or natural gas to flow readily into wellbores. The term is used to make a distinction from shale and other unconventional reservoirs, in which gas might be distributed throughout the reservoir at the basin scale, and in which buoyant forces or the influence of a water column on the location of hydrocarbons within the reservoir are not significant.

Permalink Reply by Skip Peel - Mineral Consultant on April 26, 2013 at 1:26

Maintaining a servitude is certainly a possibility.  It may not be fee land.  Then again it might. The lack of interest by XTO, EOG, COG and DVN after drilling initial wells leads me to believe their leasehold is not prospective or too small to be worth development in COG's case.  The question then becomes, has SWN tied up the only area of the BD that may prove productive?  If that is the case, I would have expected that promised JV announcement by now and for the partner to be one of those companies.  XTO seems content to drill their Gray Sands acreage in Bossier and Webster parishes.  And WLL is the only operator other than SWN to show interest although that interest may include zones other than the BD.

Permalink Reply by John D Cook on April 26, 2013 at 14:57

Just noticed ANKOR(korean national oil company) just got a permit to drill Tom-Rosa Corporation in 17-22n-1w.

Permalink Reply by North LA on April 26, 2013 at 15:09

Good find! I guess we know the JV now?????

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