Steve Smart – EVP and CFO
Qingming Yang – EVP, Business Development and Geosciences
Approach Resources, Inc. (AREX) Bank of America Merrill Lynch Global Energy Conference November 13, 2012 8:15 AM ET
Unidentified Company Representative
Thanks for coming here. Ladies and gentlemen, we’ve got Approach Resources to start this track. Most of you – Approach Resources is a pure-play Permian player. They’ve done amazingly well in the last few years. They’ve doubled their production growth. Accounts formation sturdy, if you would, from a gas player to an increased oil Permian player.
I would – we have Steve Smart, Chief Financial Officer; Mr. Qingming, our EVP of Business Development; and we’ve got Megan Hays at the back.
Without further ado, I’ll hand it over to Steve.
Okay. Thank you very much. Thank you, all, for being here today to hear our story. It’s kind of early I know. It’s a great setting. I want to thank Bank of America for putting on this conference.
Approach Resources has an enterprise value of $1.2 billion. Our mid-year reserve report at 83.7 million barrels of oil equivalent and reserves, 37% of which is prude developed. 167,000 gross acres. As we’ve advertised before, we have 500 million-plus barrels of oil equivalent of gross unrisked resource potential and over 2,900 drilling rig completion locations.
We plan on early 2013 to come out with a revised location count, which we believe will be an increase due for nothing else potentially from some downspacing as well as A bench locations that we didn’t previously count.
For the third quarter, our oil production was 8,100 barrels of oil equivalent per day, which was 65% oil and NGLs, and our revenue mix of 65% oil, 22% NGLs and 13% natural gas. So you see the strong leaning towards oil and NGLs.
Take a look here at our highlights. 64% of our prude reserves are oil and NGL. So a strong component. As far as our track record, we’ve had great growth track record as far as both production and reserves. And usually at a competitive, a very competitive cost basis normally ahead of our peers, we have a rigorous pilot program that we’re embarking on right now. We’re drilling the B bench in a development mode. We’re still testing the A and C zones. We see additional upside as I said just a minute ago from tighter well spacing and further multi-zone development.
As far as our acceleration as planned, we intend to add a third rig in 2013 early in the year around January, and that allow us to have a horizontal rig running in Pangea West, one in Northern Pangea and then one working across the field in the Central and Eastern side of the field. We currently have a $280 million borrowing base so plenty of liquidity to help us with these development plans.
Here’s our track record chart on the reserve growth, 33% growth rate over the last of the company and production 37%. Again, our oil reserves have been largely added and increased from the Wolfcamp Shale. And our oil reserves are up 30% to 23.5 million barrels at midyear 2012. As far as production goes, we’re targeting at 20% to 24% growth in production in 2012 from our program and our estimate of our production is 65% liquids.
This chart just builds up the number of location camps that we’ve announced over 2,900 here, 500 horizontal, 1,825 vertical, and the balance being recompletion and vertical Canyon Wolffork.
When we come up with our new count, what you’ll probably see is it will have more horizontal Wolfcamp well count. We will probably, as a result of getting over in the areas where we have just vertical are now going be horizontal, we will probably re-class some of those from vertical to horizontal location.
Our capital programs, as we’ve talked previously, we have two horizontal rigs running through the end of the year. We’ve done – selected vertical wells here in the fourth quarter, no recompletions. We’re still testing A and C zones and about 55% of our $295 million will be for D and C on horizontals. And this year we had infrastructure expenditures which will help us set up the full scale development of the field in the future.
2013, we talked about three horizontal rigs running hopefully around January 1. We’ll drill 35 to 40 horizontal wells. We will drill of selected number of vertical wells and do some recompletions, but as you can tell from the chart at the bottom, 88% of the budget is targeted to the horizontal well development.
Take a look here, here’s the breakout of our infrastructure and equipment. Projects, we’ve added some additional information here in the red to give you a feel for the level of the savings that we anticipate. First one is about water sourcing. We’re drilling the Santa Rosa well, shallow water wells, and we’re treating that water. We can use that and try to help in an area where water sources are very sparse.
So the anticipated savings there is about $450,000 per horizontal well. As far as the water transfer in SWD, the next section down there, you will see that on a horizontal well we anticipate that they could save us $450,000 per horizontal well. Again, in fact these wells have a lot of water and so during the flowback which we usually time to be about for six months of the wells production once it comes on. In that period you’re still in a D&C mode so disposing a lot of water cost a lot of money and thus putting at around SWD system we’ll be able to save sort of $1 amount. So again, $450,000 for horizontal well.
In addition as far as LOE savings we anticipate that, that could be around 400,000 per month which is very substantial, especially as we ramp the program, have more and more horizontal wells online that sellers disposal cost will get very high and with this SWD wells we’re going to be able to control that. And then we have purchased our own flowback equipment and that’s going to save us about $100,000 as well as we’re going to eliminate rental compressors that we have to put on these wells currently to flow them back and stay with its type of gas from the discharge line and inject the wells with it. And that’s going save both money and also gas volumes because we usually burn about 30 Mcf per day to power those compressors and we no longer had to be using that gas.
As far as oil takeaway we touched about this before. We have four round trucks which has helped us bring back down our differential. As you should probably saw from the second and third quarter, we’re over $10 in the second quarter. We’re slightly over $5 differential in the third. So that helped dramatically. And we also have the crude oil pipeline takeaway that we anticipate to get a differentials down at $2.50 to $4 as you see here.
Quickly this is a map of our area. One of the things that happened in the third quarter as you probably saw, we had some curtailment issues, plant issues, and so we had to decide to go ahead and build an alliance with ECP a reason why we thought that we could continue to produce for a few months and then the ECP would build to us but that wasn’t the case.
This area is getting very hot so these new lines you see on this map here in purple, they’re going to take the gas down to the plants that are southwest of Project Pangea, where a good portion of our gas has previously been flowing. Those plants are down there because the proximity are not close to capacity and therefore give us plenty to take away for the years to come.
Again, acreage map here, not much to say other than you can see there’s a lot of big public companies involved in this play, along with ourselves and there’s some other smaller ones as well. But most of them are public to few privates. We’re all in the early stage of development of this play. We feel like ourselves and EOG are ahead of the game more so. We’ve drilled more wells so we feel good about the results we’ve gotten.
This play again, I mean this map shows the level of activity down in the southern Midland Basin. You see how were favorably positioned around all that activity. And this shows the breadth of the play and how exciting it’s been and how exciting it’s going to be as we go forward and get further into development.
Cross-section of logs that cover 67 miles here, you can see the consistency of thickness and the consistency of the log characteristics. So it’s a very widespread blanket play that’s going to deliver results for a lot of years to come.
You’ve probably seen this before, the Wolfcamp, breaking it out between the A, B, C and D. Our plans for the short-term are just on the A, B, and C. B is in development mode as we’ve said, A and C is still testing, hope to get development mode in 2013 on those.
This may help as a new one that’s been added. Qingming did this. He comes up with some great slides, by the way. Anyway, it shows the level of consistency on IP rates as far as the as the oil account goes. In the southern part, there is 82% oil, there’s 51 well, and a little bit up further North Sea you see a circling of wells, there’s 14 wells there with 84% oil and there’s two up in the northern part and it’s 77% oil. So you can see that the early extent of this play is very wide spread, lots of running room and lots of consistency.
Our map show AREX activity, probably will spend a lot of time here. We have the two horizontal pilot wells over at Pangea West. We’re doing 3D seismic shoot over in the northeastern part. You see the green line pointing over there. And then we shot in the central part 3D and also we’re targeting with some horizontal pilot wells in early 2013 over there.
Another new slide, very, very important slide shows our top curve in green and then overlaying it, our data points from 19 of our wells, 17 B bench and 2 A bench wells around this plot. All that gray dots with the red, those are all data points and it shows how nicely the production is lining up along the client curve.
This is our usual slide on the Wolfcamp economics for horizontal well, good rates of return at various levels of oil pricing. Down to the right, you’ll see we got a B bench well. We talked about there and Project Pangea down here and 22 boe per day IP rate, and then A bench – recent A bench well was 689 boe per day. So both considered to be very good wells.
This slide has just started Clearfolk and Wolfcamp economics where a recompletion of vertical drill. Nothing’s changed there at this point. And then a summary of all of our locations, $500 million gross under resource potential again. And then quickly to wrap up, Approach has concentrated geographic footprint in the Southern Midland basin where the strong growth track record at competitive cost. We’ve performed a technical evaluation to lead to the discovery of the significant potential on the Wolfcamp and the Wolffork play.
Our pilot program has derisk over 100,000 acres. And throughout our history, we’ve maintained a strong capital discipline which only sets us up for broad skill development as we go forward.
And with that, we’ll go to Q&A.
Just to let everybody know, we have a couple of roving mics around, and please take advantage of them. Let me just start the meeting with a quick question. For the benefit of the viewers, if you could talk a little bit about how you’re seeing the play in terms of developing debentures, specifically the AB ventures and if you – I know that you plan to go deeper into the sea ventures and there are a lot of people were excited about tremendous amount of excitement about is in deeper ventures that declined. But for your purposes, if you could comment on some of the wells that you’ve drilled in the AB ventures and how do you sort of look at how do you differentiate between them as one superior than the other?
Okay. Qingming, you want to?
Sure. That Wolfcamp, the lifespan of the Wolfcamp is, it’s very safe and as you know most of the shale play for the shale oil is normally arranged from about 150 feet to about 350 feet, whether it’s field and Marcellus or Eagle Ford.
And for Wolfcamp, we have the thickness of over 1,200 feet and initially for the pragmatic purpose, we divided them into four different benches as you alluded to, you know, AB and the A and B. And for the upper 1,200 feet, which is basically A, B and C benches, we think those have the most potential. That’s where we started with and initially, given how fake this is, initially we’re trying to develop these 1,200 feet with two lateral, we were trying to frac as much as possible.
There we landed our initial horizontal wells in the upper part of the B bench and with the hope to tri-frac in those part of the B and also hopefully most part of the A can and B, another horizontal unit upper part of the space benches. And as way you know fill more wells and we used the macro seismic data to say how much fracking high we can create.
Based on the macro seismic data we have seen, looks like the fracking height is only about 300 to 250 feet even though we did not frac as much as we would like to frac however, the real results are in line were better than what we initially expected. So because of that so now we’re thinking we have to fill potentially, the other three lateral wellbore on top of each other in order to develop with four drill concentrate.
And so far, Approach and also I think as the industry has built most of their wells in Wolfcamp B bench, if you look the most of the horizontal wells, their land will be in the B bench. So most of the results we have heard so far are from Wolfcamp B bench and looks like those wells are very, very good wells and that some of those wells we have one and a half year production data. And based on the well results we have seen and those wells are going to deliver 450,000 BOE for the life of the well.
And I think EOG is sort of pointing to the similar number, they say 430,000 BOE I think our numbers are very close and huge in approach in horizontal wells in the play like in the other, offset operators. And I think our results tend to be very consistent in terms of IP and EOR and we have turned to the B bench into development. And so now that’s in four development mode. Now when we look at the A bench and C bench, really that’s the question I think how does A bench and C bench compared to the B bench, B is a done deal.
And when we look at the A bench, if you look at to the A bench, if you look at just look at the law. A bench is probably the best looking bench among A, B, and the C.
And we approach those three wells in A bench and the two of those wells in Pangea West have production data over three months and we have (inaudible) to those production data and our slide number 16, I believe, if you look at those red dots fast slide 16 that results from the air bench. Even though this 12 does not have sort of headline grabbing in IP, it only has 4,500 unit of Boe in terms of IT but over last the 90 days, it has been pretty steady and has shown in a very little decline. Looks like those two wells are uniting into produce and our type curves or above our type curves of 450,000 Boe.
So look based on the limited data we’ve had and it looks like those A bench is going to be as good as B bench, if not better than B bench, and you probably also noticed recently EOG has the last well which also filter in the that savings, I’m sorry, I can come to that a little bit later and you have just drilled some A bench well earlier and those A bench wells are pretty, pretty good as well.
And so we think we probably will turn A bench into development. There is some and we just want to see the production data a little bit more recently with 200 A bench wells in Pangea area and we have very good results and for the, when it comes to A bench, so far we have two of just where you would stay bench and we aligned in to that, we’re a little bit high on the upper part of the A bench again.
The reason we (inaudible) is that we were trying to frac as much rock as possible and try to develop this entire 1,200 state wish two steps the ladder. Obviously, based on a micro assessment data we knew that was a little bit too ambitious and we saw a frac barrier at the top of the C bench and given that and our C bench will the first C bench well is still doing well.
So going forward, working through more C bench wells and working the lines in the wellbore into the middle part of the C bench. If we do that, we think that the C bench is going to improve, probably as good as those B bench well as well.
So we’re very optimistic about that. And as alluded to a little bit earlier, EOG just allows a well from the C bench. As you probably noticed, EOG’s quite lower Wolfcamp and EOG’s lower Wolfcamp is equivalent to our C bench at the middle of camp is equivalent to our B bench and their after Wolfcamp is equivalent to Approach’s C bench.
So it looks like that the C bench is going to work as well. And right now, it looks like A, B and the C, based on the inspection and, C, based on the initial data, it looks like there’s going to be well as well.
Thank you. And if you could just quickly talk about the (inaudible) because that’s becoming increasingly important within the nat gas environment, do you see that consistently across the benches in terms of the oil cut?
That’s a very good question. And over last few months and we heard that a lot of sort of discussions on the oil cut and about the Wolfcamp shale. And you have heard different operators’ proposition there, oil percentage in terms of their acreage hugely has 42% for the life of the well at Approach. Right now, I think, we have a 58%.
And the – Pioneer has forecasted higher percentage of the oil. I think what it is is it and how early we are in the play, were still in early stage of the play, we have very limited data in the – so we have a limited data, you have uncertainty. And as a result, you say different forecast in terms of percentage of oil for the life of the wells. And at the very beginning when we had very little data, we started the quarter work very well along the trend to look at the life of the wells for the Wolfberry. And if you look at the Wolfberry well and this is (inaudible), it’s a combination of Wolfcamp and the (inaudible).
And then those wells work with anywhere between 40% to 50% of the oil cut for the life of the well and those include the contribution from obviously. That can initially you remember about two years ago when we – at the time we had very limited data for horizontal wells. We think for the life of well the oil cut is going to be about 42%. Now we have some of our wells have been producing for a year and a half. And based on the horizontal well, based on the production data we have seen, and it appears that oil cut is going to be higher than we initially thought.
And right now for the life of the well, we think the oil cut is going to be about 58%. And as in the NGL for the wells has brought another unit, 20% to 22%. The rest of those is natural gas. And as a result, if you look at the economics of the play, it’s really the oil price that is doing – have more impact and the economics. And the natural gas price and the NGL price will have an impact by the perishables. And we have done sort of our internal assessment, if you increase the gas price by even by $1 for example from where it is right now, it’s only going to impact our rigs return about to 85%. Or if the NGL price goes from 40% of WTI to 45% of WTI. It’s also looking to impact the rate of return about 45% at least oil price, which is already have a significant impact on the rate of return.
And now – so if you look at the – we have same different predictions down the oil cost for the life of the well. But if you look at the initial production well across the play, the oil cut is very consistent from the rig and currency to gearing to the Crockett County.
The oil cost initially, an average about 82%. And we have collected over 60 data point and looks like the average is up 82%. From well to well, specific well, you may have oil cost varies from in a 70% to 95% or higher. But overall, if you look at the entire trend, it’s very rig consistent.
This give us comfort that the play is very consistent looks like – it’s just like a geology and the thickness and rock’s characteristics, the oil cost is going to be very consistent as well.
Hey, Steve. Just a quick question on the infrastructure. And I know you guys spent around 15% of capital budget 2012. Just what the capacity that, that infrastructure – the running I’m going to give you. And then sort of how should we think about run rate spend on infrastructure going forward, post the capital spend you put in place in 2012?
Okay, yes, sure. As far as running room, we’re building those additional lines that we had on page 9 of the presentation. We’re building those with large enough lines of the capacity to that throughput. Through those lines, there’s not going to be an issue and those plants that we’re going through down at DCP, they’re currently about 65% utilized. In addition, DCP is putting another plant to the north and so the plants to the north right now are the ones that are under stress and have capacity issues eventually.
So you’re going to see more and more plants pop up in the area. But for now, we like the direction we’re going because we feel like that with so much development to the north of it, it’s not as logical that their gas would go down with those same plants, which will give us a lot of running room.
Now as to the amount we expect to spend in the future years, we will have some infrastructure build-out cost in each year but they will be nowhere near what we saw this year because we’re covering full-scale development across most of the field so there’s always a gathering lines to be laid there, maybe some water transport line as we get into the central and eastern part of the play. Those kind of things will happen but it’s not going to be a big chunk of our budget as you probably saw from the chart that we had for 2013.
No. We really haven’t looked at it that way per se. I mean to me, it’s a few million a year. So it could be 4 million or 5 million a year. And when you’re talking about 260 million or more million dollars, it’s a 1% to 2% kind of range portion of the budget. So I mean the benefits are great as you can see by those cost savings that we have in the slide, it doesn’t take long enough to pay out some of these products over once you get three, four, five rigs running at some point. I mean it’s going to be dramatic what it’s doing for you to keep that well cost down and lets you – let the economics really gets further enhanced.
If – are there, you just mentioned three, four or five rigs. What’s the optimal number of rigs to best develop your 200,000 acres?
You know that’s a very good question. Evidently, for a company of our size and we want to make sure our developments are paced and that we have a lot of acreage. Right now, we had de-risked about 100,000 acres. And we feel right now probably about a three rigs for next year and then possibly we can run up to five to six rigs as we go forward but we want to make sure though as we develop and all the results are meet or exceed our expectation and at the same time we can sustain our development with the cash flow and also our borrowing base.
Yes. That’s – I mean we’re in a position right now to where we easily add this third rig and any additional cash flow that we need to cover that CapEx for next year is easily covered into the borrowing base. And then we just internally, we’ve put in our models that we add a rig a year for a few more years around the 1st of every January. That’s not a formal plan but, and when I do that, I see that we are able to do that out of our cash flow and out of our borrowing base. It appears easy to believe that we’ll be able to do that varying prices. So the equity offering that’s allotted for us because it positions us to get that third rig on the ground and have plenty of liquidity to go forward.
Can you just make a comment on like – I think you mentioned that there’s a fracture in the T bench. But does that limit Wolfcamp B for you or is it like – I mean, the opportune industry like what you’re doing then in fact there was Wolfcamp D of, talking about that sort? Does that factor in the area that you have and sees those limits of Wolfcamp D bench?
The frac barrier, we say that the top of the Wolfcamp A bench which is actually a license we have. Basically, what it does is contain the frac energy within the Wolfcamp’s A bench without going into the Wolfcamp B bench.
So the – that tells us is we just need to land our horizontal lateral, it could be lower instead of the upper part of Wolfcamp A we can then be in the middle part of the Wolfcamp space. I think that’s exactly what it did. For the wells, they allow us to recent in which is a great well.
And in terms of doing deeper, obviously in Wolfcamp D is a very safe protection here and we have not sort of spend much effort on that yet, even we have in Wolfcamp A, B, and C also large acreage positions we have, we would like to get very firm grasp of all these three benches and turn them into development, then work into look at the potentials associated with Wolfcamp D and also even shallower potentials, and also the client shale that people are talking about, so.
Okay. You talked about in your recent conference calls about going into full development mode on in 2013. Can you sort of touch on what exactly that means in terms of cost and is that pad drilling if in certain point and things like that.
And what we meant is for Wolfcamp B, and we had earned that into for development. And we will begin pad drilling and also we’ll drill from one direction to the other direction basically put those wells right next to each other. That’s going to sort of minimize the rig move, and it can be increased efficiency, that’s one. And two, we probably more likely and turn Wolfcamp A into development very soon given the initial results we have seen from the three wells we have drilled and also the wells fueled by the offset operator and then working to a type of Wolfcamp B bench pilot test and we think as soon as we finished those pilot test, we’ll also likely to turn Wolfcamp C into development.
And whilst all those into development mode, and they’re all going to be sort of in the pipe drilling. By doing so, it’s really going to sort of increase our efficiency, cut our drilling completion cost down. I think another in communication of that is also working to finish major infrastructure build as you sort of heard us discussing about that during the conference call. So once we finished all the infrastructure build, and the water sourcing, SWD, the pipelines and at that point of time, it can be a real development mode. So now you’re looking at our drilling completion cost in lower stakes, middle stakes by that time our cost is going to come down $5.5 million. So that’s what we are talking about, sort of the development criteria.
(Inaudible) say that next year 2013 you’ll have one to two rigs running to doing development pad drilling or how should we think about it in terms of number of rig – pad drilling versus excellent exploration I guess?
You’re exactly right. And we’re working to have two horizontal rigs and development mode. The other rig is more like delineation. We can consider that 100,000 acres those have been de-risk and but we would have wide horizontal rig to go there in the areas which we have not drilled horizontal wells to drill wells and then watch the production data for a couple of months because they have those wells perform before we launch four development mode in those specific area. You’re exactly right. That’s what we planned to do.
And then I guess can you talk about, there has been some talk about Joe Mill and Natoko going into those horizon. Have you guys, I know you guys have a pretty good vertical program historically just have you guys seen the logs that will allow you to go potentially into those horizons or you guys are in a Southern?
In taking our area and when they – people talk about – talk about this formation in Northern Midland Basin and in our area, we call it pay shale and that is basically just phasing sort of right below the Canyon over there and approach has been sort of developing Canyon as you know for years and those are the formation. Obviously, we’ re looking to those in the future once we get the Wolfcamp A, B and C sort of completing the raft with the commercial need for development of those.
Unidentified Company Representative
Well, there goes that buzzer. Well, thanks, Steve, thanks, Mr. Yang. We welcome you. We really do thank you for coming here and presented with the 3Q for the Scarborough track and gives us a good profit into the play as we go forward. We hope not to see a repeat of the 3Q quarter in terms of your infrastructure, reabolition. How you’re going to go a lot in pursuing it. I do look forward on how you do allow the infrastructure in 2013 and we’ll be back again. Thanks a lot.
Unidentified Company Representative
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