It's been 6 months since our previous discussion on DGOC. DGOC has shown a decline < 6 % p.a., announced an acquisition in Cotton Valley (new region) and aims to acquire more this year (50/50 with capital from Oaktree Capital.
Do you still hold the same view of DGOC or are you reconsidering based on their published numbers?
There are two major risks to the equity here, both driven by higher-than-expected decline rates: (1) the returns on the wells dropped into the PDP-collateralized SPVs are earning less than the all-in cost of borrowing; (2) the actual present value of the P&A is much higher than reported if regulators force P&As on their "farting" faster than their GAAP ARO liability assumes.
Operators are deft at stonewalling regulators on P&A's (see Fieldwood shallow GOM). Diversified also bought a P&A service company recently. I think they see that risk coming down the pike. But we will see how hard regulators push.
Curious what the equity value of the SPV wells will be after (if?) the SPV term loan gets paid off...
This, albeit late chat, is a great outline on the existing and continued problem... and a few nuggets that had me wondering thinking. I appreciate the article, really wish there was a few more wonderful reads.
Interesting read, thank you! Looking at their presentations, how would you explain that this production decline hasn't happened in the past 3 years on their legacy assets? They have explained that, even though the production isn't seemingly declining, it is in fact declining but they are putting previously built wells back into production to mitigate the effect. Have you looked at that?
As a final note, they explain quite literally in their presentation what they do to improve production/mitigate production loss through their smarter well management programs that have been excluded from this report. Have you taken this into account in your FLOW model?
Tom, they don't explain why other legacy operators can't do it, but they tend to explain far more of their business model and financial model than any operator I've seen so far. In regards to their smarter well management, check out page 13 in their most recent investor presentation. That is what I was referring to. In my opinion, and on a side note, one should take into account the other cost reductions through economies of scale, as well. My point with my first question was more along the lines of; if your modelling is the case and your decline rates are accurate, how come the results haven't reflected it? You could indeed put the acquisitions as a reason, but these acquisitions seem to have (so far at least) been accretive to the underlying business in Free Cash Flow. With their more recent acquisitions (HG / EdgeMarc), you see a more steep decline, but looking at their reasoning for the acquisitions it seems like the cost per boe were so low that it was well worth it (https://polaris.brighterir.com/public/diversified_gas_and_oil/news/rns/story/rdy07pr). In general I would expect to see the results of the model to at least be somewhat reflective in their recently presented figures.
I wasn't aware of the wells to make enough money in a month to buy lunch. What was the lowest producing well in your model and how accurate would you presume this to be?
Taking a look at the sheet you reference to at the end of your post, it contains a lot more valuable information that would put the costs into more detail. I don't think they are hiding their potential plugging costs because of that. Am I correct to assume that you expect more currently run wells to be plugged sooner than anticipated, making the ARO liability on the balance sheet less accurate than one might think reading the asset retirement plans?
And at what point does your model think that plugging a well is more cost efficient than having it operate with an extremely low production?
Thanks for any clarification you can deliver on this research!
The production gains and percent improvements are not consistent with the baseline of their broader portfolio. I would like to see a list of wells where they performed remediation work, not vague slides.
Also did you notice that they dumped all their auditors at once? It's buried on page 29!
Where are they off? If you have it broken down in detail, that would be great. I only noticed a steep decline in their HG/EdgeMarc asset and I expect one of the 2 recent acquisitions to contain that as well, since they bought relatively newer assets.
On the presumtion that the slides are indeed vague, do you have a company operating in the US E&P that provides more detail on this from an operational point of view? I haven't been able to find one and I would love to dive in a little deeper. Thanks!
Robin, I looked at the Smarter Asset Management Slide in detail, and queried for the attributes in Tank Replacement (+210 MCF/d minimum uplift of 100% = 420 MCF/d; this would also include any of the line loss repair category). I only found examples of this at 8 wells on 2 pads. The Lundy North and the Rhodes. Both from Atlas in 2013 - newish wells. This was 8 wells out of a giant sample set. The slide does not indicate how many times they have executed. Is it possible they only have 2 examples? Do you have other examples?
Hi Tom, Thank you for diving in even further. This was the first time they included their smarter well management examples in their sheets, so no, I do not have any other examples.
Do you know of other companies that implement these strategies?
And besides the decline rate, do you know any other US E&P company that has such a low cost of production?
Hi Tom,
It's been 6 months since our previous discussion on DGOC. DGOC has shown a decline < 6 % p.a., announced an acquisition in Cotton Valley (new region) and aims to acquire more this year (50/50 with capital from Oaktree Capital.
Do you still hold the same view of DGOC or are you reconsidering based on their published numbers?
Well written and well-researched. Would love to see the NPV sensitivity on the abandonment liability under various assumed declines.
There are two major risks to the equity here, both driven by higher-than-expected decline rates: (1) the returns on the wells dropped into the PDP-collateralized SPVs are earning less than the all-in cost of borrowing; (2) the actual present value of the P&A is much higher than reported if regulators force P&As on their "farting" faster than their GAAP ARO liability assumes.
Operators are deft at stonewalling regulators on P&A's (see Fieldwood shallow GOM). Diversified also bought a P&A service company recently. I think they see that risk coming down the pike. But we will see how hard regulators push.
Curious what the equity value of the SPV wells will be after (if?) the SPV term loan gets paid off...
This, albeit late chat, is a great outline on the existing and continued problem... and a few nuggets that had me wondering thinking. I appreciate the article, really wish there was a few more wonderful reads.
Interesting read, thank you! Looking at their presentations, how would you explain that this production decline hasn't happened in the past 3 years on their legacy assets? They have explained that, even though the production isn't seemingly declining, it is in fact declining but they are putting previously built wells back into production to mitigate the effect. Have you looked at that?
As a final note, they explain quite literally in their presentation what they do to improve production/mitigate production loss through their smarter well management programs that have been excluded from this report. Have you taken this into account in your FLOW model?
Thanks Robin. I'm curious where they actually explain what smarter well management is and why legacy operators cannot do it themselves.
What we are doing is modeling every sell, so the effect of productions adds is taken into account.
Are you aware that most of these wells don't make enough money in a month to buy lunch?
Tom, they don't explain why other legacy operators can't do it, but they tend to explain far more of their business model and financial model than any operator I've seen so far. In regards to their smarter well management, check out page 13 in their most recent investor presentation. That is what I was referring to. In my opinion, and on a side note, one should take into account the other cost reductions through economies of scale, as well. My point with my first question was more along the lines of; if your modelling is the case and your decline rates are accurate, how come the results haven't reflected it? You could indeed put the acquisitions as a reason, but these acquisitions seem to have (so far at least) been accretive to the underlying business in Free Cash Flow. With their more recent acquisitions (HG / EdgeMarc), you see a more steep decline, but looking at their reasoning for the acquisitions it seems like the cost per boe were so low that it was well worth it (https://polaris.brighterir.com/public/diversified_gas_and_oil/news/rns/story/rdy07pr). In general I would expect to see the results of the model to at least be somewhat reflective in their recently presented figures.
I wasn't aware of the wells to make enough money in a month to buy lunch. What was the lowest producing well in your model and how accurate would you presume this to be?
Taking a look at the sheet you reference to at the end of your post, it contains a lot more valuable information that would put the costs into more detail. I don't think they are hiding their potential plugging costs because of that. Am I correct to assume that you expect more currently run wells to be plugged sooner than anticipated, making the ARO liability on the balance sheet less accurate than one might think reading the asset retirement plans?
And at what point does your model think that plugging a well is more cost efficient than having it operate with an extremely low production?
Thanks for any clarification you can deliver on this research!
The production gains and percent improvements are not consistent with the baseline of their broader portfolio. I would like to see a list of wells where they performed remediation work, not vague slides.
Also did you notice that they dumped all their auditors at once? It's buried on page 29!
Where are they off? If you have it broken down in detail, that would be great. I only noticed a steep decline in their HG/EdgeMarc asset and I expect one of the 2 recent acquisitions to contain that as well, since they bought relatively newer assets.
On the presumtion that the slides are indeed vague, do you have a company operating in the US E&P that provides more detail on this from an operational point of view? I haven't been able to find one and I would love to dive in a little deeper. Thanks!
Robin, I looked at the Smarter Asset Management Slide in detail, and queried for the attributes in Tank Replacement (+210 MCF/d minimum uplift of 100% = 420 MCF/d; this would also include any of the line loss repair category). I only found examples of this at 8 wells on 2 pads. The Lundy North and the Rhodes. Both from Atlas in 2013 - newish wells. This was 8 wells out of a giant sample set. The slide does not indicate how many times they have executed. Is it possible they only have 2 examples? Do you have other examples?
Hi Tom, Thank you for diving in even further. This was the first time they included their smarter well management examples in their sheets, so no, I do not have any other examples.
Do you know of other companies that implement these strategies?
And besides the decline rate, do you know any other US E&P company that has such a low cost of production?
Excellent article...seems likely SWM will increase declines as the well uptime will be higher.