Poised to Profit with Drilled but Uncompleted Wells

By Phillip Van Doorn
Keeping the powder dry

U.S shale producers have hundreds of drilled but uncompleted wells, called DUCs. Taking a DUC to completion took an average of 10 days during 2015, according to NavPort, which collates oil-well and rig data using regulatory reports.

“While each basin has a significant amount of DUCs, location is going to come into play when operators are deciding to frack the well — basins with the highest average initial BOE [barrel of oil equivalent] return should result in operators holding onto DUCs for longer periods of time, in hopes to get the biggest bang for their buck,” according to Amie Parenti, NavPort’s director of analysis services. 

In an interview Friday, Parenti said the number of drilled but uncompleted wells in all basins held by reporting companies had grown by 34% during 2015.

Parenti provided lists showing the top 10 reporting exploration and production companies among the four shale basins with the largest number of drilled but uncompleted wells. 

To be sure, we don’t know if we’re already in the middle of a sustained, significant rise in oil prices. Despite gains in the past month, West Texas crude oil was up only 2% year-to-date through Tuesday.

So there’s no way of knowing how long a company will need to wait (or survive) to maximize its profit when completing the DUCs. This is why we added another column to the data for publicly traded companies: ratios of long-term debt to equity as of Dec. 31.

DUCs by basin

The data supplied by NavPort includes average BOE per well produced for each reporting producer in the specific basin within the first six months after fracking is completed. It also includes an efficiency measure, dividing that average production figure by proppant short ton. Proppant is the sand that is combined with water and chemical additives and pumped into a well under pressure to open cracks in the shale from which oil and gas can flow. It represents a major portion of the total cost to bring a well to production.

Here are the lists of the top 10 producers in the four basins with the largest number of drilled but uncompleted wells (DUCs). The list is sorted by average barrel of oil equivalent (BOE) during the first six months of production per proppant short ton used:

This information can be a useful tool as you do your own research into which companies may profit the most from a sustained rebound in oil prices. 

It’s important to do your own research and consider a company’s overall financial health before making an investment. You will also need to be ready to make a long-term commitment. Rising prices in the oil market over the past several weeks do not necessarily mean a long-term recovery has begun.

Read more: http://www.marketwatch.com/story/these-us-shale-oil-companies-are-p...

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Replies to This Discussion

Permalink Reply by William C. Morrison on March 18, 2016 at 5:36

I am surprised that Anadarko does not show up in the Permian and Eagle Ford areas.  I had read somewhere that one of the big producers had very carefully managed its risk and was out a head of all the rest of the E & P crowd.  No Sandridge either.  But Sandridge is a bit shaky at the moment.  I had also read that there were several thousand DUCs in the Permian Basin alone, wells just sitting and waiting to be completed and brought on line.

Permalink Reply by Skip Peel - Mineral Consultant on March 20, 2016 at 10:15

The variable missing is cost.  A good number of DUCs gives an operating company leverage with completion related companies.  Since many of those service and material companies are in a similar financial bind and attempting to hang on for better days, an operator can offer a contract for a guaranteed number of wells and get competing bids.  As commodity prices improve and operators are willing to complete some of their backlog the competition for those jobs will be fierce. 

Permalink Reply by William C. Morrison on March 21, 2016 at 2:25

If it walks like a duck and talks like a duck, it must be a DUC.  I am told by locals that it cost almost as much to frack a DUC as drill it.  Some E&P companies were already under contract to drill, so they drilled.  But not under contract to complete the wells, thus we have DUCs all over the place.  There are somewhat more than 2,000 DUCs in the Permian Basin alone.  And yes, the competition for the good ones will be fierce just like the man says.  But what is a good one?  By the way, Frack Tech is around the corner and about a quarter of mile from them is a two acre storage yard full of Frack equipment sitting idle and collecting rust.

Permalink Reply by Skip Peel - Mineral Consultant on March 21, 2016 at 5:12

Depending on lateral length, cost to complete can be more than the cost to drill.

Permalink Reply by olddog573 on March 21, 2016 at 10:09

what are your thoughts on companies that haven't had the money to experiment with longer laterals and such during this down turn, will they be able to make better wells once they get to drilling again or will they still make 2010-2012 types of wells?  I.e, is the longer laterals and more proponent (spelling?) a product of the completion companies or the operator such as CHK and EXCO?

Permalink Reply by Skip Peel - Mineral Consultant on March 21, 2016 at 10:19

The operating company (CHK, EXCO, etc.) "designs" the well.  The drilling program and the completion program.  Every company that has the ability to drill long lateral (HC) wells will do so excepting rare instances.  Keep in mind that not all companies have extensive, contiguous leasehold.  In order to drill a lateral, north or south, through multiple sections, a company must be the operator of those existing units.  I haven't examined the EP Energy (formerly El Paso) HA units to see how they are aligned.  Their units may be complimentary to adjoining units operated by others that would provide more opportunity to drill long laterals.  I don't know any companies that have not, in the past, had the money to drill long lateral HA wells.

Permalink Reply by William C. Morrison on March 21, 2016 at 10:40

Skip is right and the word spelled is "propant." which is sand of certain size.  It seems the sand from Wisconsin is the most desired.

Long laterals is what Goodyear was doing in the Tuscaloosa Marine Shale just above the LA/MS state line.  Laterals like 7,000 feet and they had many stages to be fracked which is a very expensive operation.  Perhaps that is why Goodyear is near to bankruptcy (or perhaps have gone bankrupt).  Anyway they are not currently drilling any wells at the moment.  There are other additives in the Frack mixture, some like Diesel fuel, detergents, emulsifiers, etc.  And even the frack mixture is designed by the company's like CHK, EXCO, etc.  It is said in the Permian Basin the desired Frack mixture is the "slick" mixture.

Permalink Reply by Skip Peel - Mineral Consultant on March 21, 2016 at 10:53

The vast majority of hydraulic fracture stimulations are "slick water" across all the major basins as far as I can tell.  The frac designs are all quite similar with the exception of the number and sequence of pads that are pumped.

Permalink Reply by William C. Morrison on March 23, 2016 at 3:13

I had to go back and do some research.  It was Henry Petroleum of the Midland/Odessa region that started using a "slick" frack formula in 2006.  As a result of his Geologist using the enhancements to flow of fluids out of the well, that Henry racked a bunch of successful Permian Basin wells.  He is known for the "Wolfberry" strata which is a combination of the Sprayberry and Wolfbine shale areas.  Mr. Henry, still alive, sold out his business for a little more than $700 million dollars and is semi retired now.  He is an Texas icon as a pioneer in the oil patch.

Prior to his use of accelerants, the normal frack used other chemicals, sand and 99% water to frack the wells.  It was a common practice in the old days.  The addition of slick materials greatly enhanced the production of the Sprayberry wells.

Today all kinds of materials and chemicals are used, including detergents to keep the well clear and operating.  Every well here in the Barnett Shale has its 50 gallon tank of detergent sitting out in the open next to the Christmas tree is but an example of some unique technology to improve capture of well products.

Permalink Reply by Skip Peel - Mineral Consultant on March 23, 2016 at 3:22

The "slick" in the name slick water is owing to the addition of chemicals to reduce the surface tension of the water.  Reducing the surface tension allows more pumping pressure to be exerted on the rock.  I'm a little familiar with the Wolfberry from a driller friend.  Hadn't heard of Mr. Henry.

Permalink Reply by Dion Warr, CPL on March 23, 2016 at 4:14
If this article is to be believed, the amount of DUCs is situated more in the neighborhood of hundreds, and is starting to come down in response to production pressure and reserve value markdowns:

http://mobile.reuters.com/article/idUSKCN0WN0BK

The Permian is still moving - I just made a trip through eastern NM and the Panhandle. New well rigs and workovers being put to good use in the area. Granted, other regions are dreadfully slow and the yards in Odessa and Midland are almost scarily full, but equipment is still being put to use to the north and west.
Permalink Reply by Skip Peel - Mineral Consultant on March 23, 2016 at 4:24

Interesting.  Thanks, Dion. That's what $40 crude will do.  Can an increase, be it ever so modest, in the rig count be far behind?  The increase in drilling may be significant at $45 but in that case will crude make it to $50 this year?  Or $60 next?  How many basins with challenging economics will not see sufficiently high prices to make them viable for the next 5 to 10 years?  Looks like we may have answers to some of those questions in the next two quarters.

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