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Permalink Reply by Dion Warr, CPL on October 4, 2013 at 8:43

Dingo:

 

There are a number of wells that are still slated as WOCR (waiting on completion rig).  Skip keeps a decent track on these, if he would be available to share.  The Shreveport district scout report make for a good source for primary data on these.  Being that these wells will generally not flow in any appreciable quantity as a vertical completion, the wells are functionally equivalent to a shut-in well (capable of production, as soon as someone finishes the drilling, completion and/or frac).

 

There is not much pressure to convert these wells to producers yet.  There are several factors, as you mention dry gas trades at a low enough value so as to make further substantial development impractical, and bringing additional volumes of gas would only compound the problem.  The ROI in the Marcellus is currently more attractive where it can be developed, and there is still substantial drive in the Marcellus to hold existing leases by drilling and producing wells.  Once that lessens, I suspect that the Marcellus production will similarly level and possibly recede to an point such that an equilibrium based upon ROI and acreage attrition will be the primary factors driving development.

 

There still is a historical premium on liquids compared to equivalent gas costs based on equivalency and BTU, so the oily plays still rank ahead of dry gas.  Takeaway and refining capacity issues along the northern border will cause more of an effect in the Bakken than in those areas nearer to home (e.g., Texas plays), where piping and infrastructure can more easily accommodate delivery to the market and refining centers.

 

The Haynesville has entered the second phase of development - manufacturing and buildout.  This will be driven by revenues and cost metrics rather than the initial sunk costs of development (G&G, Land, Legal, Lease Acquisition).  Production and profits will dictate the pace.  Until the natural gas price ascends to a level that would warrant another wave of wholesale lease acquisition ($6 - $8+, depending on the source) and subsequent buildout into the lesser tiers, or another "game changer" surfaces, things should remain static.

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Permalink Reply by Skip Peel - Mineral Consultant on October 5, 2013 at 3:41

Dingo and Dion~

As of Oct. 1 the state lists Haynesville Shale wells as follows:

127 Waiting On Completion

28 Drilling

55 Permitted, Not Drilling

2475 Total

There are 25 wells listed as Shut-In (Status Codes 31 - 37)

Note that new horizontal wells are predominantly Cross Unit Lateral well designs.  Each of those wells effectively drills ~1.6 times the lateral length of earlier non-Cross Unit wells.  Therefore the 28 wells currently drilling, if all are CULs, would equal ~45 wells with a lateral contained fully within one section.

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Permalink Reply by Keith on October 5, 2013 at 10:15

I think it's due to the high decline rate of shale wells. That's a major difference between conventional plays and shale plays. In shale plays you have to keep drilling in order to keep production even. In conventional plays you can drill, complete, and watch the money come in until it's time to work-over or open another zone to produce in an existing well.

The Eagleford and the Bakken will also follow the same pattern as the Barnett and apparently the Haynesville. That's why the big players Shell and Chevron are having second thoughts about shale plays. I don't think that's a major problem for shale plays. Leave shale to companies that don't have the overhead.

My projection for a couple of years now has been to expect higher Nat Gas prices, I'm sure I waivered at times, but I think you'll see higher prices followed by higher rig counts in shale gas plays.

 

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Permalink Reply by Arrest_ID on August 7, 2015 at 6:48

Dion,

Lots has changed since you wrote this post.  As an investor in 2019 natgas futures, hoping you will provide an update on the ballpark minimum HH price required to cause a new lease build out at Haynesville.

There is so much press on the monster wells and low cost in the NE - it seems like the market assumes Marcellus/Utica and associated gas will set the price at HH.  

As we know, once the investor capital is turned off and the previous capital is destroyed - we will go to the half-cycle marginal cost...and then the full-cycle marginal.  Not conjecture.  Basic math.  

The US will needs another 15 BCF/day by 2019.

The US needs to replace over 16BCF/day of supply each year due to shale/conventional ng declines.

Utility usage, chemical plants, Mexico export demand all surprising to the upside. 

Some think that marginal MCF will be coming out of Haynesville once the dust settles from the current carnage.  

Obviously, lots of costs have fallen over the past year as the service and pipeline companies have joined the E&Ps in the 'go-forward/sunk cost' decision making club.  Also, some drilling occurs to meet previous pipeline commitments.  One would assume these are either temporary or one time events.

Guess a lot of this boils down to all the technology and productivity improvements - how much of it is due to the characteristics of the play; how much due to zeroing in on the core...and then the best parts of the core; are some methods sacrificing the long-term for a quick bump in results...and most importantly, how much it is transferable to the Haynesville play.  

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