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# Linn Energy, LLC (LINE) Message Board

• rrb1981 rrb1981 May 11, 2012 4:33 PM Flag

## Excel and KOG Bakken Declines

First, does anyone else absolutley hate the new excel?

I just finished playing around with the values from one of KOG's well data. Ideally, we would have monthly data or cumulative production to better model but using what values were in the KOG May presentation and having tried a variety of curve fitting equations, I settled on the following equation, which is within 4% on the tail end but of course, given that they don't give us values for 210, 240, 270, 330 etc, I have had to iterate and of course, the curve doesn't fit perfectly on the fron end, but fits very nicely on the tail end. Production = 6912*(Day)^(-.427). If you plug this into excel, you should get fairly decent numbers that are close(keep in mind, I could refine this a lot more with some tweaks, but this is fine for 5 minutes of work).

BTW this is from well MC 13-34-28-1H. Would be nice to layer multiple wells on top of each other and build a composite model.

If you plot the area under the curve, you can get a nice cumulative production number. So, drum roll....using this back of the envelope equation, one could expect around 400 boe/d of production around the 2 yr mark which seems far too high but would be a 30%+ decline from end of Yr 1 to End of Yr 2, so not entirely out of the ballpark but probably skewed to the high side, so perhaps the equation will need to be tweaked and one must also remember a slight change in trajectory on the downward slope has a huge effect on outlying production and having to extrapolate some of the numbers between day 180 and 360 can hurt the equation. Also note the well is on pump and not flowing under reservoir pressure.

So, we need more data to get a better composite curve. Need monthly production data points.One other item that likely isn't an issue is whether these numbers are based on flow meter at the wellhead,or based on sales..which might be skewed due to timing of receipt etc. I suspect these are actual measured wellhead volumes from a flow meter or tank level guage.

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• Exactly. Now, these first couple years companies such as KOG, TPLM etc should do well (evene though their IP rates haven't been as good as forecasted, but that may be intentional.)

There are also other issues - infrastructure, demand, rig availability that come into play.

Some folks think that these companies are on the verge of minting money, and they may well be for a couple years,, but as we've seen most of it gets plowed back into the business (so no dividends, nor will there ever be) and before too long they are just another Tosco.

There is also the question of sustainability. At some point, the maximum daily withdrawals will be reached - now its over 500k/day, but some say 1M/day may be the optimum withdrawal rate. Not just because of infrastructure/other constraints, but because much more than that would depress the price to clost to lifting costs.

• While I think it is great that you have the interest to actually look at some numbers instead of reading just general statements from articles there is a bit more to consider.

It is all available data.

Much of it can just be obtained directly from Whiting or from Continental.
If you wanted third party data you can get it directly from the State.

https://www.dmr.nd.gov/oilgas/basicservice.asp

Also, I mentioned after your last post, you will also need to do your numbers by oilfield/or project area as well as by operator, and you will also need some info on how long the laterals were.
You can delete or remove those before 2009 because of technology differences.

If you just bunch some data all together and call it bakken decline rates then it really does not reveal much.

Whiting has a summary by oilfield on their presentation that you can follow as a starting point if you really want to compile some numbers.

Or, you can just call Lynn Helms at the State of North Dakota since they already have most of what you may want.

• I'll tinker around with the field by field data from KOG. I think looking at the data, it is safe to say that decline rates are likely in the 70% range, with perhaps a little lower depending on length of lateral, number of frac stages etc, Also important is gas/oil ratio.

Not sure why everyone is so concerned about the decline rates, while they do differ from one field to another and from one basin to another, they more or less mimic all of the other non conventional fields. You know these fields are going to decline 60-90% in Yr 1, followed by another 30-50% in Yr 2 (that would be 30-50% of Yr 1 ending rates). The companies drilling have to get payout in the first 18-24 months for these wells to be worth pursuing. The "tail" is where the value comes from since the producer recoups most of their initial cost in Yr1 and Yr2 and then redeploys that capital. So, the value comes from stacking those flat tails on top of one another.

The faster they can get payback, the quicker they can redeploy that capital into another well and repeat.

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