Idle Rambling Regarding The July, 2020, Dashboards -- July 26, 2020

Continuing observations regarding the EIA dashboards:

I was asked yesterday whether the Permian was better than the Bakken. With regard to crude oil, mano a mano (individual well vs individual well): my answer -- impossible to answer. Depends. Depends on what one is measuring. Depends on time frame. But at the moment, I would prefer having mineral interests in a Bakken well than a Permian well.

I don't track the Permian so I could be wrong, but it's my understanding that it costs a lot more to drill / complete a well in the Permian than in the Bakken, and if that includes the mineral acquisition rights, the costs in the Permian are considerably greater. Again, I could be wrong.

Look at those dashboards, again (below). The EIA shows August oil production in bpd per rig, new oil production, and August natural gas production:

• Permian: 964 bbls of oil/day and lots of gas 1,867 mcfpd (which is a "negative" in this pricing and environmental market)
• Bakken: 2,147 bbls of oil/day and lots of gas, 3,570 mcfpd (which is a "negative" in this pricing and environmental market); 
• Bakken oil / Permian oil: 2.23x;
• Bakken nat gas / Permian nat gas: 1.91x

Years ago, as part of the Saudi disinformation campaign on US shale (SDC-USS), it was said that US shale could not "turn on a dime." It would take months for oil production to respond to market conditions. Not only can "new-well production" turn on a dime, so can legacy oil production.

In the Bakken, note how remarkable the August numbers were -- both the production and the fact that the number of rigs remained at an all-time low. Rig counts don't matter.

• what matters month-to-month: a) pricing/demand; b) takeaway capacity; c) cost of takeaway capacity; d) DUCs reaching "expiration" dates;
• what matters over six months to a year: a) pricing/demand; b) fracking spreads; c) takeaway capacity; d) DUCs/trending;

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The Dashboards

Re-posting:

See this post.

EIA dashboards:

• EIA pdf, Bakken: https://www.eia.gov/petroleum/drilling/pdf/bakken.pdf
• EIA, pdf, Permian: https://www.eia.gov/petroleum/drilling/pdf/permian.pdf
• EIA, pdf, Eagle Ford: https://www.eia.gov/petroleum/drilling/pdf/eagleford.pdf

Yeah, this is what a V-shaped recovery looks like:

In addition to the notes and commentary above, see the comments at this post from a yesterday:

A reader commented:

It's high grading. Going from 50 rigs to ten rigs, means you're only driling the 20% best wells.

My reply:

I would prefer to say operators (those few who are drilling) are drilling the "best locations," and from there some great wells are being reported.

The "best locations" in the geographic Bakken are due to some unique properties of the geographic Bakken. Compare the Bakken and the Eagle Ford, for example, with the Permian:

http://themilliondollarway.blogspot.com/2020/07/the-bakken-is-back-eia-dashboards-july.html.

What interests me is the "parameters" the operators (who are still drilling) are using to determine the "best locations" and what parameters are used to decide whether to drill the middle Bakken or the Three Forks. This, of course, is proprietary (closely hold) information and not known to those outside the decision-making process.

For example, why is QEP not drilling the Grail, one of the best fields in the Bakken; and why is CLR still drilling the Brooklyn, one of the more "average" fields in the Bakken?
And, then from there, deciding on the best completion strategies: I am seeing quite a variation in the completion strategies.

It's almost as if the Bakken operators can fine-tune this so carefully, they have locations that they will drill with $20-oil; locations that they will drill with $30 oil; locations that they will drill with $40 oil; and, so on.

And, although many of us (including myself) get excited to see the rig count increase, in fact, the rig count actually has little impact on total production in the Bakken.

Remember: "almost 100%" of currently drilled wells are DUCs. That "almost 100%" may be on the high side but probably not by much. Of the 67 wells coming off the confidential list so far the quarter, not one had an IP reported (though some did have some production, and in some cases, quite a bit):

themilliondollarway.blogspot.com/2020/06/new-wells-reporting-3q20.html.

One last thought: the decision to add a rig is not made overnight. My hunch is that between the time the decision is made and the rig added could be several months. What did the operators see three months ago that led to an increase of active rigs from ten to thirteen?

I find it quite fascinating.

By the way, keeping track of the operators with active rigs and the number of active rigs employed by each operator, for me, is a leading indicator of what operators think about the future.

Right now, if Slawson adds a third rig, that would mean a whole lot more to me than if CLR adds a third rig.

Likewise, it would be huge if Whiting shows up with an active rig on the list. Did anyone note that Whiting is reporting a lot of new wells, but has no rigs on the active rig list?

Wow, don't get me started. This is simply so fascinating.