Since there has been much discussion about decline rates, I thought I'd do a little investigation as to the topic. Here are some tidbits I found.
"Earlier this year, Peters & Co. Limited reported that five multi-frac horizontal plays showed average first-year decline rates of 72 per cent, with the median first-year decline rate on 10 oil resource plays at 60 per cent. The median first-year decline rate on horizontal wells in nine gas resource plays was 75 per cent-15 percentage points higher than the oil plays.
The decline rates are important, Peters & Co. noted, because companies with higher proportional exposure to such plays tend to have high corporate decline rates, which Peters warned will often lead to increasing maintenance capital requirements to maintain production.
An example of this is the Bakken tight oil play in southeastern Saskatchewan. According to Saskatchewan government figures, horizontal Bakken wells have an average 74 per cent decline rate during their first year of production. On average, they decline by 24 per cent in the second year and 22 per cent in the third year.
Peters & Co. says what these decline rates mean is companies active in the play need to be continually drilling and completing wells just to stay in place production-wise. It points to one major producer, which it estimates will have to spend $785 million in 2011 just to keep production flat in the region.
(Pretty cool picture on that website)
"First, the decline rate on tight oil wells is very high. This means that the flow of oil from the well declines to a relative trickle typically after about a year. The result of this is that the drillers move on quickly in search of new pastures. So the infrastructure to pipe the gas away will often be struggling to catch up, arriving too late for the bulk of the gas and in some cases may not be worth putting in at all."
February 2010 (getting old, I know, but a valid point):
When I read a press release which includes IPs it's usually with a great deal of skepticism. The only thing you can tell for sure from an IP test is that the well isn't dry. Only after several wells have been on production in a given area and a "type curve" established, can the IP rate be used to approximate reserves.
And finally, from a blog on "the Oil Drum" website (debates go on on other websites as well):
Decline rates are THE problem. If you have a well with an initial production rate of 1,000 bpd and a decline rate of 80% per year, after 1 year it will be producing 200 bpd, after 2 years it will be producing 40 bpd, after 3 years it will be producing 8 bpd, after 4 years it will be producing 1.6 bpd, and after 5 years it will be producing 1/3 bpd. (Assuming an exponential decline curve, which is typical).
It will not produce 46 bpd for 30 years.
At this point the well has recovered nowhere near its hypothetical 500,000 barrels of oil, so you have to drill an infill well near the first, frac it, and start over - but then you are back on the decline curve again.
So, imagine you have thousands of these wells, all of them in steep decline. You have to drill thousands more to increase production. Soon, you have tens of thousands of wells in steep decline, so you have to drill tens of thousands more to increase production. At some point in time you just can't find enough money to drill enough wells to increase production, and then you find yourself on downslope of the classic Hubbert bell-shaped production curve, which, unbeknownst to you, you have been following up until that point.
No we are not.
We are waiting for your explanation of using corporate averages for acquisition modeling.
AND assuming a new acquisition is dilutive under efficient market theory.
Which not surprisingly is why you did not understand my WACC explanation.
It all does go together. So no one is surprised you got it all wrong.
I did get a kick out of all the whining about your feelings morphing into complaint about condescending treatment (both accurate by the way) and now to sunny.
You really do not understand the basics but that is not what got you into trouble. It was not even your arrogance. But your would be bully routine.
YOu are stuck with you basic mistake. Running off and pretending you are an engineer will not save you. Nor will ignore but it will allow you to prattle on in the pecular world you belong to.
RRB I assume you are trying to "win" some sort of debate with Norris (since I have him on ignore I don't see the posts), but I suggest you do the same since his circular arguments and pointless attacks are just that.
rlp nice post on decline rates! A lot of info to absorb!!
One thing to keep in mind with these high decline rates is that companies that already have a large flat production base can easily manage the high declines. These wells have 2 or 3 yrs of high decline before slowly dropping into the flat part of the curve, where most wells exhibit 6-7% annual decline.
I was always enamored with the original Atlas Energy (ATN) because they had 30+ yrs of upper Devonian ("shallow") conventional Appalachia gas wells to the tune of about 100,000 mcf/d from several thousand wells! That slug of production exhibited about 6-7% decline and they were growing the company by drilling vertical and horizontal Marcellus shale wells. They were raising their overall company decline rate, but so long as they didn't drill too many Marcellus wells, it was very manageable. After 4 or 5 yrs, the Marcellus wells would become part of the "base".
You will likely see an increase in Linn's overall decline rate in the coming years with the GW and Bakken helping push it up, while the recent acquisitions in E Texas & Hugoton will serve as ballast to moderate the rise since both of those deals are sub 10% decline properties (i.e. mature).
I would argue that so long as management allocates capital for maintenance, E&P companies can manage high decline. I believe E&P MLPs can manage high decline drilling as well, but it will take both a strong base of flat line production as well as discipline to know that you shouldn't base your DCF off of wells that aren't yet near the flat part of the curve. For example, in the GW, Linn is pouring several hundred million in drilling high return wells. Wells that will drop 65% or more in Yr 1, followed by say 25%-35% in Yr 2 followed by say 10-15% in Yr 3 before hitting ~6% natural decline. Linn knows, like most producers, they will have to take the cash flow from the first couple of years and redeploy it back into the field to keep production up. That is fine, because the wells pay out quick and leave the company with a nice revenue stream once they flatten out.
The problem that many producers face is that they are drilling at a rate of 2x or 3x their cash flow. They are borrowing money to fund drilling and the reserves they find/produce are serving as collateral for those wells. They repeat over and over and when they can no longer borrow, they face a massive crunch.
rlp you are into a very complex area of reservoir engineering. there are several delcine rates that are used depending on reservoir. etc.
for economics a good "rule of thumb" in a typical reservoir is the a wells generate 70% to 80% of of their economics in the first 5 to 7 years. can be less for some of the horizontal wells or slow decline fields or more depending on field/reservoir
here is a view of marcellus as an example which is two to three times as good (life and economics) as an austim chalk well for example
I realize each basin has it's own unique decline rate; what I had hoped to find was a chart showing say the top ten basins and the respective average decline rates for each.
But in most basins it appears that horizontal wells have a minimumm decline of around 50%, maximium of 90% (any more than that and it wouldn't be economical). But I think the point is when will the turning point be where drilling costs can't keep up with the productuion rate? Granted we are probably years away, and again each basin is different, but within a few years will we be hearing the term "peak oil" again?
page 6 shows marecellus decline curve.
below is more from the spe on the various types of decline curves-page 19. as an example the fetkovich curve came from the e&p company I worked for. fetkovich is a well known reservoir engineer
who spent years developing his model which is one of several type curves used
Again, glad to see you included COG, up 10% the past couple days.
I am LOL also.