Yesterday, Southwestern Energy (SWN) released their first early results from the Lower Smackover Brown Dense play in southern Arkansas and northern Louisiana and the Street was less than impressed. Southwestern's first well, the Roberson 18-19 #1-15H in Columbia County, AR, is still recovering frac fluid and has been on production/flow back for 20 days with a best rate in a 24 hour period so far of 103 barrels of oil, 200 Mcf of gas and was at the time producing 1,009 barrels of water per day from 8 stages out of an 11 stage design.
- To be clear, the 1,009 barrels of water production listed in SWN's press release for that same 24 hour period are:
- Frac water, NOT formation water.
- And definitely not water from the Smackover B wet zone above the Lower Smackover which had been an early concern here.
- As the load water falls off (45% of load recovered as of yesterday) the oil production has come up as expected but the well is still in the process of cleaning up and this may take 10 more days or it could take another month or two. This is their first well in the play and they don't know exactly how frac load recovery will behave.
- At this point there is no point in venturing a guess at a stabilized oil production rate. People shouldn't think of this "IP" as "initial production" but rather as an "in progress" rate.
- Notably, the 3,600' lateral was landed, with some difficulty, in the lower third of the Lower Smackover, where permeability ranges from 0.1 microdarcys up to 2 - 3 microdarcys (very tight rock, not granite but quite tight). SWN intentionally landed in the lower part of the interval in an attempt to avoid fraccing up into the wet zone and after coring the vertical noted that it was in one of the lowest perm levels of the 300+ foot thick section.
- For comparative purposes the Barnett is around 10 microdarcys while the Haynesville Shale gets down into the nano darcy realm.
- With the lessons learned in the Roberson well they drilled the Garrett 7-23-5H #1 well, a 6,536' lateral, roughly 30 miles to the southeast in Claiborn Parish, LA. Here they landed the lateral in the upper third of the lower Smackover where they see greater permeability (potentially up to 5x) than the rock seen in the Roberson lateral. In a nutshell, longer lateral, more frac stages (20+) and more permeable rock should lead to improved results, all other things being equal, and while the oil shows seen in the first well were that of florescing well cuttings the oil shows reported from the second well are actually "a little bit" of free oil in the pit. This well should be completed during March.
- A third well, with a 9,000 foot lateral, is currently drilling in Union Parish, LA
- Well costs - Analysts always ask what the initial wells cost and what they think the company can get them down to eventually. The answer is always something along the lines of the initial wells being loaded with science and not representative of what they would be in delineation mode and again not what they would get down to in development mode. The answer to the question gives a little color in terms of the first four wells being "over $10 mm" with future wells to cost less ($7 to $8 mm) but without an EUR really it only provides a little more color on this year's budget.
Nutshell 1: Rarely if ever do we see the first well in play turn out to be the best and that's highly unlikely to be the case here. The Street was quick to condemn the well and SWN without having more than the cursory information in the 4Q11 press release and once out with their morning snippets (some of which took the step of actually downgrading the name to Hold) they are hard pressed to reverse the call "sorry clients, sales force ... bankers... oops". We'd remind people that the first horizontal Bakken well (not at all a direct comp but worth noting) IP'd at "only" 275 bopd and with practice and a steep learning curve wells now routinely pierce the 3,000 BOEpd level with some more than double that rate. This well is proof of concept and it worked. It flowed from only 8 of 11 stages in a lateral that was short and partly redrilled in a low perm area and as the company has previously stated, OOIP on SWN's half million plus net acre position is estimated by the company at 30 billion BOE. SWN is not alone either as (COG), (DVN), and (XOM) are rapidly moving ahead with delineation efforts.
Nutshell 2: SWN's management team is the opposite of what I'd call a crew of hypesters. They have been conservative in their development of the Fayetteville and Marcellus Shales maintaining a solid balance sheet while transitioning from discovery to delineation to manufacturing mode in almost flawless fashion. They are "underpromise, overdeliver" types. And they don't believe in growth for the sake of growth but do have extensive experience in horizontal unconventional plays and are logically, given the macro back drop on natural gas, eager to transfer that skillset to the liquids realm. So when they say they know more about the Brown Dense play now than they did about the Fayetteville Shale at the inception of that program in 2004 we take it with more than a grain of salt. When others rapidly follow them into the play it adds weight, especially when one is a Major not known for playing small ball. And instead of trying to earn the "we cracked the code" award, they are sharing information with offset operators. Smart. So when they say, after having drilled over 2,500 horizontal wells as a team, that they are encouraged by the first well in this new play and are looking to immediately improve on well results in upcoming tests (oil in the pits at #2) it means a lot more than a set of analysts who felt free to label these in progress results as "disappointing" and who in almost unison predicted a 10% fall at yesterday's open with only the tip of the data iceberg and a bad set of assumptions about water.