In this tutorial, you’ll learn the most critical and also the most commonly overlooked step of building any model: adjusting the numbers and making sure your assumptions make sense. We’ll adjust the wells drilled, realized price differentials, royalties, operating expenses, and more, to ensure that the cash flows from the Utah region are in-line with market expectations.
Table of Contents:
- 1:22: Lesson Overview
- 5:46: Adjusting the # of Wells Drilled
- 10:42: Adjusting Royalties
- 11:49: Adjusting the Realized Price Differentials
- 14:59: Adjusting the Utah Operating Expenses
- 21:10: Reviewing the Taxes per Well
- 24:40: Reviewing the EUR per Average Well
- 28:30: Reviewing the Reserve Risking
- 31:39: Confirming the Overall DCF Value from the Utah Reserves
- 34:53: Recap & Summary
Summary, Commentary & Model Tweaks Transcript
Uinta Acquisition: Summary, Commentary and Model Tweaks
Hello and welcome to the final lesson in this module on the reserves and the production from this newly acquired territory, this newly acquired acreage and the producing wells, as well as the undeveloped, unexplored regions in Utah that Ultra Petroleum just acquired as of the time we’re doing this case study. So what we’re going to do now is not anything modeling-specific related, but something else that’s equally important, if not more so, which is looking at the numbers and adjusting them up or down as appropriate.
This is really important because this is something that a lot of other financial modeling training programs just tend to skip over it entirely. If you go to a two-day seminar or a three-day seminar, or even something longer than that, you have so little time that you can’t really focus on something like this. They’re just so busy teaching you the mechanics and how to set up formulas that they never take a step back to say, “Okay, well where are these numbers coming from? Where do we get them from? Do they actually make sense? Does the company contradict itself? Do we find evidence to not believe the company’s numbers or to believe higher or lower than what they have?”
So, here, as you can see from my outline, we’re going to be digging into a lot of these numbers in the Utah region in-depth, and as we’ll see, some of these numbers in some cases will be close to ours. In some cases they’ll be off by a lot. In some cases we’ll have to change our numbers, and in some cases we’re going to keep disagreeing with the company and use our own set of numbers instead for very specific reasons.
So, just to recap what we went over before, in the very beginning of this, we had set up these assumptions for the company’s net remaining reserves, their annual production, and then we saw how that declines year-over-year until these proved developed producing wells are completely worn out. Then we looked at their new wells they’re going to drill in this territory.
We looked at some of the key assumptions for them, the working interest, the royalty rate, the estimated ultimate recovery, initial production rate, the drilling and completion cost, and so on and so forth. So we went through and did a lot of that work. We then had our wells by location and reserve type, so proved undeveloped, probable, and possible over here. We came up with our drilling schedule down here.
We looked at what the decline curve might look like based on some of the numbers we found in Ultra Petroleum’s own presentations and then third- party sources. Then we aggregated our production and we estimated all of our cash flows. Then finally at the end of this analysis, if we just scroll all the way to the bottom under Total right here, we got to the total discounted cash flow value from this area, which is around $800 million, a fair premium to the acquisition price, $650 million.
But what we’re going to be doing now is digging into this number and seeing if it’s really justified, if it should be higher than this, lower than this, if some of our assumptions should be the same or different. The reason why this is important is because, remember, the company’s share price changed significantly right after this acquisition took place.
So if we find evidence that perhaps the market did not value it correctly, well then maybe the company is mispriced. And maybe there is opportunity to make a long or short bet for or against the company that could actually net us some profits in the future depending on how quickly the company’s shares become appropriately priced.
The other reason why this is important is because with Wyoming and Pennsylvania, those two regions, the main ones the company is operating in now, with those they’re a little bit more similar to each other in that they’re more developed. Even the geology is a little bit more similar in those regions, the operating expenses, the production expenses, things like that. They are somewhat different. But they’re still closer together than they are for the Utah region. Because, first off, they’re both predominantly natural gas, whereas Utah is 100% oil, at least this particular basin that we’re in.
So, it’s important to get this right because a lot of these numbers will actually be quite a bit different from what we have elsewhere. So we’re going to look at actually eight different topics here. So we’re going to start by going through wells drilled, because remember there were some questions up here.
Is it really right to have 14 wells drilled per year over the course of 40 or 41 years here? Is that too little? Should it be over a shorter time period, is that too much? So we’re going to look at that. We’re going to look at royalties and price differentials here and make some adjustments, again, for very specific reasons. Then we’re going to go into monthly operating expenses per well.
As you’ll see the company is assuming very different numbers from what we have. So, based on that we’re going to have to change those numbers as well; same with taxes. They’re calculating them differently and they’re also making different assumptions. The estimated ultimate recovery per well, this is probably the most interesting part because this is one where consistently the company here seems to be giving figures across all regions that do not really foot internally.
So, who knows? Perhaps we’re not looking at it the right way. Maybe they’re not giving us enough information to really calculate it appropriately. But it seems like there is something suspicious going on, and in particular in Utah they give a massive range. They’re saying in this region that the estimated ultimate recovery is anywhere from 160,000 barrels of oil to 380,000.
So it’s a range of over 2X at the low end to the high end, which is very suspicious. Most companies try to give a tighter range than that, so this is going to cast a lot of doubt on their numbers and some of their internal projections here. We’ll also look at reserve risking, and then finally the overall value at the end. We’re not going to change too much in terms of reserve risking.
We’re going to kind of stick with what we have. But we’ll also look at some of their assumptions and see how applying their risking to our numbers and changing around our assumptions slightly is going to make a difference and change some of our results in this model.
Then, at the end, as I just said, we’re going to look at the overall value. Here, what we’re really looking for is our overall numbers; our overall calculated and applied value should definitely be a discount to their numbers because we’re being more conservative in a lot of cases. Not only with the estimated ultimate recovery, which I just mentioned, but also even with things like expenses, we’re probably a bit higher than they are in expenses. With the production decline rates, we are probably more aggressive than they are.
They have more of a flat type of curve, whereas based on our analysis and digging into the numbers we have a steeper production decline curve there. So, all of this is going to have implications in our model. Let’s start with step one right here and go into the wells drilled. So, this one is pretty easy and it’s pretty obvious that we’re way too low. We just made this initial estimate of 14 per year because we took the total number of locations and divided by the years or something very rough and approximate like that.
But take a look at this. First let’s turn our attention to the Seeking Alpha article, and on page three here, “sees a 3P inventory of 575 additional vertical locations, which represents a 12-year drilling backlog for a one-rig development programs $70 million capital budget.” So there they’re telling us directly that they expect this to last for 12 years. So, already, just from that simple math, well 575 divided by 12 is around 48. So it’s about three times what our projections are currently, or actually even more than that.
Now, this $70 million CapEx number, they mention that repeatedly. They have $68 million in a few other spots. I want to draw your attention to the Earnings Call transcript from the acquisition and I’m going to take you to page 13 here, where I’ve highlighted some comments. So take a look at this. One of these analysts is saying, “And so the $70 million well cost, $70 million CapEx program, we can just divide by $1.5 million, that’s the D&C cost in this region, to get the annual well count?”
CFO’s answer is, “Yes.” So they’re pretty much telling us there, “Well, $70 million divided by $1.5 million is of course around 47 wells per year.” So we have a lot of evidence that drilling should be a lot higher than this, and then if you want even more evidence… Well, turn your attention to the supplemental earnings presentation and on this one if you turn your attention to page 21, take a look at this. They map their CapEx, and what’s interesting is that you see it in 2013, 2014, but then by 2025, about 12 or so years after it starts, it declines and goes to zero.
Now, it’s not clear if they’re assuming a lower number of wells that are actually drilled in these later years, or if they’re assuming that the expenses themselves get lower. But in any case, the key takeaway is that after about 12 or 13 years, or so, this just stops entirely. So we have a ton of evidence now that on the basis of all this we should be assuming a shorter period for the drilling and assuming more wells drilled per year.
Now, what’s the impact of this going to be? Well, of course, as with any type of DCF analysis, since we’re assuming more cash flow up front than we get, it’s going to push up the net present value, even though the absolute value is not going to be that different if you look at it over a long time frame and ignore the years. Since we’re getting more cash flow up front, we’re drilling more up front, the NPV is going to go way up and our value here should also go way up. So that’s a quick way that we can check this.
Now, let’s go down here and take a quick look at our values, so about $800 million. After we do this we’re going to go back, do a quick check here and make sure it actually did go up as I just explained it. So let’s go back to the Assumptions tab, and so let’s go down. What I want to do here is go into this Utah region.
So, our base gas case, now remember for Utah we assume the same numbers in the base gas case, the high gas case, and also the low gas case, and the reason is because Utah is 100% oil. The company is acquiring these reserves strictly for cash flow purposes and to get money to reinvest into more natural gas exploration and development. So we’re not going to change this because it doesn’t matter what the gas price is because this is oil to begin with.
So, let’s go down here and what I’m going to say is 47, and then of course for the rest of these we’re going to have to copy and paste all those values. This is way too high right now. We want to go down and have this continue for 12 years. So if you look at this, it continues until about 2025, which pretty much matches the investor relations presentation, the acquisition presentation we just looked at.
So, let’s have this and let’s make this go down to 2025, and then the rest of this, you can have that go down. I’m going to change the font color to blue because these are hard-coded numbers now. So we have that. Let’s look at our total, 564 versus our total estimated future locations of 575, pretty close. Off by a little bit, but close enough for our purposes. So we have this. We have this drilling now all in the beginning. It starts in 2014 because that’s the first full year following the acquisition close at the end of 2013.
So let’s go back and take a look at this. Our value has sure enough gone up by a whole lot. It’s up by about $250 million now because, again, the cash flow generated that part doesn’t actually change. If you look at this number, the total cash flow generated and if you just ignore the years, this is not much different if at all different. But the discounted value of that cash flow is much higher because we get it earlier on in this model.
So it makes a pretty big difference, and now you can see why it’s so important to tweak these numbers and to get them right. By the way, this has nothing to do with our view of the company. This is not really about our view being pessimistic or optimistic. This is just trying to match reality and match what the company’s plans actually are.
So I’m going to mark off step number one as being completed right now. Now we’re going to move on to step number two, and then eventually step number three. So, with royalties, this one is pretty easy. But in this region we had assumed in our Assumptions tab up here… We set this to 18%.
But actually if you look at the earnings supplemental presentation and you go toward the end, slide 22 here, technically it’s an 82.5% net revenue interest, which really means a 17.5% royalty rate. So, this one should be a bit lower than what we’ve assumed. This is a pretty easy adjustment to make. They don’t even mention this in too many other places in the model. It’s almost insignificant. But just to get it right and to be as accurate as possible, we want to change that to 17.5% instead.
Does this even really make a difference? Well, I’m going to mark off step number two as being completed, and then we’re going to investigate that question. So does this make a difference? A little bit of a difference, but really it’s virtually the same number that we had before. It’s off by maybe $10 million, $20 million, something like that, which is very small for something that is worth over $1 billion, at least as of right now. So let’s go back up and let’s keep moving here. So, step number three, price differentials, now this is an issue that I mentioned before.
One of the problems with price differentials is that even if the market prices for oil and gas are similar no matter where you are in the country, whether it’s West Texas Intermediary (WTI) prices or NYMEX prices, or whatever else you’re using… Depending on where you are there may be a differential to the market price because you may be further away from the pipeline, which is definitely the case for Utah.
Now, Pennsylvania is very close to major pipelines; a lot of companies have developed quite a bit there. Wyoming, same type of idea, a bit further away; price differentials have been higher historically, but recently they’ve really narrowed. But in Utah, there’s still quite a differential and it’s going to take some time for the infrastructure there to be built out. Now, the problem here is that in the very beginning, in our Assumptions tab, remember we assumed the same price differentials for all the regions.
So we’re now going to have to go in and change that, and we can keep these for Pennsylvania and Wyoming. That seems reasonable. But for Utah, we’re certainly going to have to go in and change at least the oil differential. The others are irrelevant because we don’t have gas, we don’t have NGLs in Utah. Now, in terms of where to get this from, well again I would invite you to turn your attention to this second to last page of the supplemental earnings presentation.
Here, you can see it broken down, 80% of NYMEX oil prices. So, in other words, if the NYMEX oil price is $100, the company is only going to realize $80 instead of $100. Then, for further evidence to back this up, if you turn your attention to the Earnings Call transcript following this acquisition, where they describe a lot of key metrics around it, very interesting to read through.
I highly recommend looking at this because it shows you a really good view of what equity research analysts and even private investors and other people would ask when an acquisition like this in the oil and gas industry takes place. So let’s go to page eight.
So, on page eight if you take a look at this, so here President and CEO are saying they’re using about a 20% differential. So they’re saying, “$100 oil, call it $20. We start with $80 and then you’re going to have to help me with some of what the operating costs are.” So we have direct evidence there that it’s 80%. So, what we’re going to do now that we know this, I’m going to mark it complete.
Let’s go up here and… Let’s go over here and I’m going to say for the oil difference versus the price deck, now we’re going to change this to 80%, and also we’re going to change the color of this to reflect the fact that this is now a hard-coded number. We’re now not looking it up or pulling it in based on anything else. So we’re making more of an input cell and making the formatting match up.
So we have that, and we can add comments and footnotes to this later. I’m just going to change the number itself right now. So, what kind of differences does this make? It makes a bigger difference than you might expect. Let’s go down and check it out. So look at this. We’re back down to about $850 million.
So we went from around $1.05 billion down to $850 million, a difference of about $200 million, just by assuming an 80% differential or an 80% realized price rather than a 93% one versus the market price. So pretty big difference overall there, and that’s why it’s so important to get these numbers right. Just changing one or two small things could dramatically impact the value.
So, that’s price differentials. Now the next thing is monthly operating expenses per well. Now, this one is interesting because what we had in the beginning here, we already knew going into this that this is inaccurate. Because, first off, in the Pennsylvania region, there are no production taxes, or at least very minimal taxes, Wyoming is about 78% of revenue, but Pennsylvania is negligible.
Now, we’ve justified this because the company’s production, the bulk of it is from Wyoming anyway. So, assuming a per-unit expense from this wasn’t that bad, it was an okay simplification. However, in Utah the cost structure is going to be very different from either Wyoming or Pennsylvania because these are very young reserves, relatively speaking, not as much developed infrastructure.
That makes some things maybe more expensive, more time-consuming, but may make other things cheaper because of the region and the differences in pay and infrastructure costs and labor costs there, and so on and so forth. So, we had these assumptions here and now what we’re going to do is dig in and see what they should really be. So, again, let’s look at a few key numbers here.
Go back to the earnings supplemental presentation and you can see here they’re saying about $10,000 a well per month. So that’s one estimate. Now, it’s not clear if that’s just including the LOE expense or the other expense, or both. But we’re generally going to assume it’s both because they only list OpEx and taxes here, and these taxes are not income taxes. These are production taxes based on revenue.
So there’s that, and then if you go and turn your attention to the Earnings Call transcript, so page eight of that, so here the manager of business development says something very similar. I have this highlighted in yellow, “$10,000 per well, per month,” and then here they’re saying, “Take $6.50 of taxes off the $80,” so they’re estimating some of the taxes.
But the key thing is that we have an estimate of about $10,000 per well, per month. So, what does this mean in terms of our model? Well, let’s go back, and as I say here, basically our implied numbers are a lot higher than theirs. So let’s take a look at this. Let’s go up to the proved developed producing region and see exactly what I mean there.
So, proved developed producing, remember we have 39 proved developed producing net wells here. So, let’s go and add up our LOE expense and then our other expense. Then what we should do now is divided by 12 to get the monthly cost, and then divide by 39 because we have 39 wells. So, we’re trying to get the per well expense right here. So 19, and really this means $19,000, so almost $20,000 per month, per well, because these numbers are in thousands.
Now, what does this look like going forward? Well, it changes a little bit overtime due to production differences. But essentially, it does scale down overtime. However, we’re starting at a much higher level in the company overall. So looking at this you might think, “Okay, so what do we do? How do we adjust this? Do we even bother adjusting this?” Because, yes, we start off at a higher number, but eventually we get to a very low number here as well and I would say it’s still worthwhile to adjust it.
One of the reasons for that is that, for example, let’s go down to our proved undeveloped region over here, and I’ll show you one of the problems with this. So, let’s take our LOE expense and then our other expense, let’s divide by 12, and then let’s divide by the number of wells so far in this period. So, let’s take the 40 there and we have this. Let’s go down a little bit, and so we see here that… Well, first off, let’s check that this is actually working the right way.
One of the problems, it’s hard to do a direct comparison here because our expenses are based on units produced in that month or in that year, whereas theirs are based on the wells. But in any case, no matter how we look at it, it’s clear that we are assuming a premium because the first year we have about $14,000 per well, per month. The second year we have about $10,000, then $8,000. So it’s clear that we are probably above their numbers.
So what we want to do based on our findings so far is to go up and what we’re going to do is just kind of cut these numbers in half to more closely match their own estimates. So we’re going to “haircut” these numbers to more closely match their estimates. Now, I don’t want to take them down by exactly 50% because, first off, we saw that overtime our numbers declined anyway. Then, second off, even if the company claims that we still want to be conservative and assume slightly higher expenses.
So instead of multiplying this by 50%, I’m going to multiply this by 60% and then do the same thing for other operating expenses, and you can copy and paste these values over. We have that, and again same idea. I’m going to change the formatting of these because these are now hard-coded input cells. So, we have that, and then same idea here. So we have that. Now, let’s just do a quick check of some of our numbers here once again.
So, LOE expense and then other, divide by 12, divide by 39, now we get to around $11,600, so between $11,000 and $12,000. So, now much closer to their estimate for OpEx in this particular region. Not exactly a perfectly scientific method, but again our goal is just to come closer to what they have overall. So I’m going to check this step off as completed now and then what I also want to do is see what impact this has had on the overall value.
So, it goes up to around $900 million, a difference of about $50 million, by cutting the expenses by about 40%, which is probably less than you might think. You might think that if you cut operating expenses by 40% it’s going to make much more of a difference than this.
But it actually doesn’t because in this case, keep in mind, a lot of this value is being driven by the realized commodity prices. Also, the CapEx is much higher overall than operating expenses because these are all new wells that are being drilled. So, keep that in mind as well, that you might think it’s going to be very significant.
But if you look at the grand scheme of things, actually the operating expenses make a fairly low impact on the overall discounted cash flow value versus other variables that I just mentioned – the realized prices, overall commodity prices, the CapEx, and so on and so forth. So let’s go up and move on to the next step of our process now.
So, now we’re going to go into the taxes per well, and you can see here I have basically laid out what the problem is. But again, turn your attention back to page 22 of the presentation, and they have about 8% in taxes. These are both based on a percent of revenue, so 5%, 3%. Then the acquisition earnings call transcript, so if you take a look at this, when one of the analysts here asked about taxes, the manager of business development said, “On the order of 8%, 8% to 9%.”
So we have that. Now, what do our implied numbers come out to? Well, as I say here, our numbers are based on the unit of production expenses. So, it’s a little bit hard to compare them directly. But what we’re going to do is change these a bit and we’re going to try to come close to their percent of revenue here.
Now, one of the reasons this works is because, first off, even if it’s a percent of revenue the state or the local jurisdiction may change that percentage as commodity prices rise or fall. So, those aren’t necessarily going to stay the same overtime, and also oil prices are not changing dramatically. In all the cases, we’ve pretty much assumed $80 per barrel going forward.
So, it’s not as bad as you might think. It’s not that much of a simplification to just change this to a per unit expense, even though arguably we should make this a percent of revenue expense instead. It’s just going to be a lot of work to go into our model and change that around. We’re going to have to relink every single page here, so we’re not going to worry about that.
So, let’s see, in any case, what our production taxes as a percent of revenue come out to. About 3% and then going all the way down, 3%, 4%, so we’re about at 50% of what they’re projecting. Now, if we go into some of the other regions here, so the proved undeveloped region, let’s take a look at these numbers. So, 3%, and then if we go down let’s take a look at what this is overtime, 3%, and 4%.
So it seems like this is the case for both the undeveloped region, and then also the proved developed producing wells. Let’s go up, and so what I’m going to do here is just assume a pretty high premium of what we have right now. I’m actually going to increase this up to $0.70 per 1,000 cubic feet equivalent. We have that, and let’s copy our formatting up here. Again, we can footnote this and add comments and everything later, but for now I just want to make sure that we get the numbers themselves correct.
So, now let’s go and take a look at this again. So production taxes as a percent of revenue, 7% going up to around 8%. So not exactly the 8% to 9% range they give, but certainly it looks like it’s much more reasonable and much more accurate overall versus their numbers.
So you can see how in this case we’ve adjusted some expenses downward, other and the lease operating expense. Then other expenses like the production taxes we’ve actually adjusted upward based on some specifics in the Utah region, at least in this particular basin, this particular local municipality.
So let’s go down and check this off, and then the next few things we want to look at, we’re not necessarily going to change that much here – the estimated ultimate recovery per average well, and then the reserve risking. One other thing I want to do before moving on is, as always, go and take a look at how the tax change impacted our DCF value here.
The short answer is not by that much. It’s back to about $850 million, whereas before if you recall it was around $900 million. So even doubling – more than doubling really – the taxes per unit produced doesn’t make as much of a difference as you might think. For the same reason that changing operating expenses around doesn’t make as much of a difference as you might think it would for, say, a normal company in an industry outside of energy.
Let’s now go back and let’s look at the last few factors here, the estimated ultimate recovery per well. Now, this is really interesting and I want to highlight some of the numbers here because you see just how vague the company is actually being with their numbers. Now, if we look in the presentation, take a look at this. They’re not giving us an average, but they’re giving us a bunch of different types of wells that they found.
So, one of them has 446,000 barrels of oil, 410,000, 190,000, 119,000. So there is a very, very wide range there and we don’t know exactly how many of those different types that they’re actually finding because they’re not specifying how many of each of these might potentially be in this region. So it’s really sort of vague information to go on.
Then to further compound that, if we go to the acquisition transcript. So we have a couple references to the estimated ultimate recovery per well. One of them is on page four. You can see here, look at this range they give. They say 160,000 to 380,000. This is a massive range to be looking at.
So, that’s pretty big, and then if we go to page 11 of the presentation takes a look at this. One of the analysts points out that it’s a massive range, 100 to 360. They might have mentioned that in another part. So what is the actual average range here? Look at this.
He directly asks the CEO what the average range is and the CEO replies by saying, “I’m sorry. We can’t just give you an average number across the whole field,” and then says, “It doesn’t work that way.” So bottom line is that the company is not actually giving us an average, which of course is nonsense because to do their calculations internally they must have worked off of some average.
They’re not going to look at every single well individually and come up with a guesstimate for each of the hundreds of wells there. They have to come up with some kind of average. So they’re just not giving it to us. So the question then is what do we actually do? What’s really interesting about these numbers is – I’m going to show you. I’m going to go back to the investor presentation now.
So they’re giving a very wide range. But if you really dig into this and just look at a few simple numbers here, so their net reserves, the 3P total is 90,600, which really means 90,600,000 barrels of oil. Then the economic wells are 618. Now, the treatment with royalties here is a little bit tricky. It’s not clear if these are actually before or after royalties. Economic wells usually means gross wells, so we’re going to assume before royalties.
But, in any case, let’s just take that number, 90,000 divided by 618, and I say here… Well, I’ve already actually done the math. But 90,000 divided by 618 is actually 146 which is very low, which is certainly a lot lower than a lot of these numbers. It’s lower than basically everything except for the UGR type curve here at the bottom.
So, we think based on this and based on the fact that the company’s numbers don’t foot internally, they’re probably being very optimistic with the estimated ultimate recovery in all these types of wells and it’s probably significantly lower than what they’re stating. So, let’s go back up and just go back to that page briefly.
Then, once you take out royalties from that… So even if you assume this is actually after royalties and you gross this up, well again same idea because take a look at this. Even if you gross this up it only gets you to about 178, and if you assume this is actually after royalties, well this gets you up to about 121.
So no matter how you look at this, no matter how royalties are being factored in or not factored in, you get to an estimated ultimate recovery per well that’s a lot lower than what they have. So, here we’re actually going to stick with our numbers and we just think overall they’re overstating it. They’re not being internally consistent, and overall we have more faith on our estimates based on their overall data than we do in their numbers as quoted in their Earnings Call presentations and investor presentations.
So we’re just going to stick with what we have for now. So I’m going to mark this off as completed. The last thing I’m going to look at before looking at our overall value is the reserve risking. So here, as a reminder, we applied 100% reserve risking to proved developed, proved undeveloped, 50% to probable, 10% to possible. What did they pick? Well, let’s go down to where I have the notes and then look in our usual places. So, page 22 of the earnings presentation.
They’re saying 15% risk on 40-acre locations and 25% risk on 20-acre locations, which basically means 85% reserve credit and 75% reserve credit if you look in the Earnings Call transcript over here… Go to page 17, and so take a look at this. So they’re saying that they risked the PDP reserves by 15% and they risked the development wedge by 25%. It’s not clear what they’re doing for the proved undeveloped reserves, if they’re actually risking that by 25% or if it’s actually the 15% here. We’ll look at it both ways.
It seems based on a couple other factors that, again, they’re being a little bit inconsistent here. Because in one part they said there’s a different number for 40 acres versus 20 acres, but then in another part they said proved developed producing is one number and then everything else is a different number. So we don’t know exactly what they’re doing, but we’re going to try both scenarios here and just see how our numbers compare.
So, once again, let’s go down to our overall value here at the end, about $850 million. We’re going to keep that in mind, and let’s go up and change around the reserve risking. So, let’s change it to what they have, and let’s say that we have an 85% reserve credit for all of these. Then, for proved undeveloped, since they said 25% for the development wedge, let’s say 75% for all these and see what the value comes out to.
Okay, so using their numbers we get to a value of closer to $1 billion. Which makes sense because we are adjusting down the proved developed producing reserves, which count for a significant value. But when all is said and done, overall we are still increasing this because we have a 75% credit applied to probable and possible, as opposed to 50% and 10%.
So, that makes sense intuitively and we would expect it to be quite a bit higher with those assumptions. Then if we wanted to change this around further, so if we had, say, 85% and 85% as may be the case here, we don’t really know, now this goes up even higher.
Now this is more like $1.05 billion. So, it’s clear that their numbers are higher. Their reserve risking and reserve credits are much more aggressive than ours are. But we’re actually going to leave our numbers for now. Again, this is something that we’re going to look at later on when we roll up all the numbers and look at net asset value per share. We’re going to go into this and see what the effect is.
What if we assume slightly different numbers here? What impact is that going to have on net asset value? Is there some type of margin of safety no matter what the numbers here actually are? So we’re overall satisfied with it, and the numbers are pretty much what you’d expect. We’re simply being more conservative than they are with our numbers.
Then the overall numbers here, so generally we would expect our numbers to be at a discount to theirs because we’ve assumed slightly more in expenses. We’ve assumed a quicker decline curve. We have not been as aggressive as they have been with their reserve credits and reserve risking, and that’s probably the most important factor. So let’s just take a quick look at what they have in different sources.
Page 18 of this presentation, they’re saying the PV-10 value, so in other words the present value assuming a 10% discount rate, is about $1.135 billion. Then, if you look in other sources they pretty much say the same thing. So if you go to the Earnings Call transcript right here, if you go to page five, look at this, a discounted PV-10 of over $1.1 billion and they have the values for the other regions here as well.
So just out of curiosity, let’s go and take a look at ours and see how they compare overall. So they have 265 for PDP, 470 for proved undeveloped, 365 for probable, 35 for possible. Now our overall number, of course, is much lower than theirs. Our number is about a $300 million discount, but again we’re using pretty conservative assumptions. So the fact that this is a discount to their number, that’s expected.
But what’s interesting to note here is that even with our much more conservative assumptions, for the most part – especially the decline rates and especially the reserve credits – it’s still showing that the overall value of these reserves and the production here is still greater than the acquisition price. So $850 million to $650 million, if you think about that for a second, that’s about a 31%, 30% premium to the acquisition price. So on the surface, this doesn’t actually seem like a terrible deal, and so far at least it seems like maybe the market got this one wrong.
Let’s go up and take a look at some of these values. So, proved developed producing first, so we have about $360 million in value. What do their values look like here? So they estimated a PV-10 value of about $265 proved developed producing. In all likelihood that’s probably because they’re applying an 85% reserve credit, in other words 15% risking, to that.
If we applied that our number would also go down. It wouldn’t be that exactly, but it would be lower and closer to the $265 million. Now, for proved undeveloped, so we get to about $322 million. They have $470 million. So our proved developed producing is higher, but our proved undeveloped is lower.
Then, for probable, they had $365 million and for possible they had $35 million. So, probable, let’s go down and take a look at this. We have $134 million, and then for possible we have $30 million. So what’s interesting here is that possible is very similar, but probable there’s a very, very big difference there. That has the biggest delta out of all these reserve types.
Our possible is actually almost the same as what they have. Proved developed producing proved undeveloped, the total is about the same between those two, but the allocation is a little bit different and really here it looks like the difference comes to us in the form of the probable reserves. It looks like that’s the biggest difference overall and that explains possibly why our PV-10 value is so much different from theirs.
So, it doesn’t necessarily mean we have to change anything right now. This is just something we have to keep in mind as we go through and eventually form our investment thesis about this company, which we’ll get to in the next module in the next set of lessons coming up after this. So, that’s it for now. As I said, coming up right after this we are going to be getting into the full roll-up across all the different regions, all the different reserve types.
Ultimately, what we’re going to be working toward is in our Assumptions tab over here, we want to be able to calculate net asset value per share and look at it in a couple different ways. So we want to be able to look at not only the different regions, but also the different reserve types, the effective hedges, the effective taxes, and some expenses being tax- deductible, others not being tax-deductible, the effect of the G&A expense and so on and so forth; undeveloped acreage as well in Colorado, here.
So there are a lot of other things to take into account and to do this we’re going to have to do a big roll-up across all the regions, all the reserve types, and also do quite a bit with the tax treatment of the company. A lot of it will not even be that relevant here because this is actually a full-cost company, Ultra Petroleum.
If it were successful efforts, some of this would actually make more of a difference because intangible versus tangible drilling costs work differently for a successful efforts versus full-cost company. But we are going to look at this and build in the capabilities anyway, just in case you want to apply this model to a successful efforts company in the future. So we’re going to go through all that.
Then, ultimately, get to a Net Asset Value per share at the end, look at some sensitivities, and then make an investment recommendation about this company.
Files & Resources
- Lesson Transcript
- UPL - Earnings Call Transcript from Quarter Prior to Deal Announcement
- UPL - Earnings Call Presentation from Quarter Prior to Deal Announcement
- UPL - Uinta Basin Acquisition Earnings Call Transcript
- UPL - Uinta Basin Acquisition Presentation
- UPL - Seeking Alpha Article on Uinta Basin Acquisition
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