Taylor L. Reid – Chief Operating Officer & Executive Vice President
Oasis Petroleum Inc. (OAS) 2013 IPAA OGIS San Francisco Conference Call October 1, 2013 2:25 PM ET
Hi everyone. Today, we have Taylor Reid, Executive Vice President and COO of Oasis Petroleum.
Thank you, Chris. Good morning everybody. Happy to be here to provide you an update on some of the great things happening at Oasis. We’re going to talk quite a bit today about a recent acquisition that we announced about three weeks ago. It’s a transaction that’s – it’s actually four separate transactions that we were able to sign up all about the same time, that should close in the very near future, but very accretive to us as you’ll see. Substantial add in terms of acreage and inventory, about 40% on a number of measures. A great fit with the position that we have, and very importantly it plays well to the operational advantages that we think we have in the basin. So we’re talking quite a bit about that.
Of course, our forward-looking statements. So, the information that I’m going to show you here is pro forma. So it’s based on a combination of Oasis prior plus the additional assets that we acquired. In combination, you can see we have close to 500,000 acres now in the basin, which places us up near the top of acreage holders in the Bakken. We produce combined over 43,000 barrels a day, and importantly about 90% of that is oil. So, very much oil focused. Proved reserves over 200 million barrels and provide PV-10 of close to $5 billion.
Let’s talk about the inventory a little bit. We now have 400 operated spacing units which provides us an inventory of over 16 years of drilling at our current pace with 13 rigs running. As I mentioned, it really plays well to the operational efficiencies and the infrastructure that we currently have in place.
The map on the page here focuses on the two acreage positions. In gold, you can see what was our existing position; in the blue are the positions that we acquired, in total total close to 160 -- a little over 160,000 acres, and those are really split into two areas. On the east side of the basin, on the north end of what we call Cottonwood, about 25,000 acres. And then on the west side of the basin about an additional 136,000 acres. Again, what you can see is these blocks are – they’re concentrated, contiguous, and they’re controlled blocks. I’ll show you here in a minute the average working interest in the blocks that we took over close to 70%.
So 90% of what was acquired is operated very consistent with what we held. Very important to us to be able to control phase of activity, the operations that we’re doing on the blocks. The inventory is accretive on all fronts, over 40% increase. The thing that we’re really excited about is all of the things that we’ve been working on for the past three and a half years since we became a public company, getting the people in the systems and processes in place to really extract value out of our position immediately or able to apply that to this set of assets.
As you saw, it’s right by where our assets currently are. The other thing we’ll talk about here in a minute, the infrastructure is a fantastic fit as well. So, we’re going to be able to take the infrastructure we currently have on our position, expanded it into these set of assets and get the benefits in really short order.
This slide gives you a little more detail on the inventory. As I mentioned, 400 spacing units in total. These transactions added over 100 additional spacing units. In terms of absolute inventory number of wells that we think we’ll drill, we’re now over 2800 locations. That’s based on four Bakken wells and four Three Forks wells per spacing unit, which we feel really comfortable with, and there is upside to that which I’ll show you here in a minute. Across all these inventory measures, both gross, and then also on a net basis you can see over a 40% increase to our inventory.
So, this slide focuses on our downspacing efforts. We’ve got 22 separate spacing tests going on across our position this year. You can see all those highlighted in the rectangles, and then on top of that you can see all the lighter color blue boxes which show spacing tests being done by other operators in the basin, which quickly noted with all this work, again it is in and around the positions that we just picked up. So, all the work that we’ve been doing to understand the right number of wells per formation is going to directly apply to this set of assets. In terms of maturity, these assets are mostly held at this point, but they’re not heavily drilled. There’s one well per spacing unit. Again with that upside, probably additional seven to 12 wells per spacing unit as we go into full development.
This slide shows a lot of the work being done in the lower benches of the Three Forks. On the slide, you see a series of dark triangles. Those are all the wells that we drilled at the end of last year and early this year at the core through the full section in the Three Forks. Based on that work, we now have actually drilled a couple of wells. So, over on the east side, you see well number 1 right here, that well is drilled and that will be completed in the near future. This well number 2 is actually currently being frac’d.
So those are both in the second bench, and we’ll have data on those as we get closer to yearend. Then a couple of wells on the position that we bought three and four, a second bench and a third bench test. So, we’re really encouraged by what we’ve seen so far when you combine that with all of the additional tests that you see highlighted in the blue circles on the map gives us a lot of encouragement about the lower benches. It’s going to be really over the next year as we learn more before we come out and tell you what we think that’s going to add in terms of inventory. But like I said in the earlier slides, we’re not counting lower bench inventory at this point.
We’ve been able to grow both our production and our reserve base aggressively over the past three years. You can see that that’s going to continue as we exit this year we project with the acquisition having a total year production of about 33.8 to 35.8. That’s our range. If you take the midpoint, it’s going to result in production growth of 50% for 2013. Likewise, if you look on the reserve side, you can see 50% growth in reserves, and that’s based on pro forma reserves as of midyear, and that’s not at yearend. So, these assets continue to help us on this trend of aggressive growth both on production and reserves.
One of the things that we’ve had a lot of success on over the past couple of years is in pulling down the well costs. You can see at mid-2012, our well costs had peaked right at about $10.5 million. This is our average well cost because they’re not all the same. They’re kind of very dependent on where we are in our position. We will pull that down by the end of this year to $8 million. If you include the impact of our well services, we actually have a frac crew in the basin. You can see the average well cost will be at $7.8 million by yearend. We think that with continuing efficiencies that we’re getting in cycle times with pad drilling, that will pull that down by the end of next year to $7.5 million and then with well services to $7.3 million.
We’ve made a lot of progress there obviously. In three years, you’re going to see about a $3 million decrease in average well costs, a big impact across the whole position, but one of the places we’ve been able to make some really, really big strides has been in some of the areas that historically have been a little less prolific for us. So, in areas where it’s shallower, a little higher water saturation, we’ve been able to reduce our well costs to below $7 million. So if you look on the table on the right hand side of the graph, you can see that the inventory for the lower half of our inventory, the midpoint of 525,000 MBoe. Our rate of return for that versus the upper half of our inventory is about the same, and that’s the impact of that cost reduction that I was talking about.
As we move into 2014, we’re going to have even more of our activity concentrated on pad drilling. All the work that we’ve been doing on subsurface spacing, understanding the lower benches of the Three Forks is being used to then configure the optimal setup on the surface. So in 2013, we had about 60% to 70% of our wells on pads. As we move into 2014, that number is going to move up to 80% to 90%. So, we’ll get more of the benefits of efficiencies from pad operations across the position.
I mentioned well services earlier. We’ve got one frac crew currently. For every well that we frac, we save about $500,000 per well. So, pretty significant number when you consider it’s an $8 million well. On top of that, there’s an additional $200,000 that we get for the benefits from third parties that are in our wells. This has been very impactful to us. It has obviously helped us reduce our well costs, but have also gotten us more control over the delivery of our frac which we think translated into improved performance.
When you look at the infrastructure, what you can see when you look at the acquired assets here, in light blue again is what we’re buying. You can see that the infrastructure is a fantastic fit with this set of assets. In this case on the map, you see the oil gathering system that’s currently in place. On that system, we currently gather about 85% of our volumes, our operating volumes. We think with some expansion of that infrastructure, gathering systems being built out, we can have the acquired assets in a similar shape within about a year. So that’s going to be a big focus for us and one we can bring a lot of value in the short term.
Similar story on the GAAP side. We’ve got a great infrastructure that gathers about 90% of our gas currently. We’ll expand that into these positions, same with our saltwater disposal systems. We own and operate all of our saltwater disposal with about 55% of our produced volume going to our gathering systems that will ramp up to about 85% at yearend. We’ll do the same thing on this set of assets as we get control of them.
From a funding standpoint, as I mentioned upfront, the combined acquisitions cost about $1.5 billion. We’re funding this through debt. We actually completed a high yield offering for $1 billion here in the past two weeks. That will fund a significant portion of the deal. The remainder is in our revolver. We have a $1.5 billion borrowing base in our revolver. So those two things combined give us ample liquidity to complete the acquisition and then also to take us through the current period (inaudible) cash flow positive. We think that will be sometime in 2015. Prior to doing this acquisition, we project it being late 2014, early 2015 with the acquisition and a little increase in activity that we have planned. It looks like that’s probably going to be more mid 2015 at this point.
The other thing we’ve done in response is we’ve ramped up our hedges a bit. So, end of 2013, we have about 32,000 a barrels a day for the fourth quarter, for 2014 first half 26,000 barrels a day hedged. Second half 20,000 barrels a day. All those have average scores of around $90.
So, in summary, we are very excited about this acquisition. As I mentioned, it really plays to our strength. We think we’ve developed some real operating advantages in the Williston Basin. These assets are right in around what we do. The Williston Basin is the only place that we operate. So, we’re highly focused on this asset, high oil concentration, a lot of benefits from the improving operational efficiencies that we expect to get by increased pad drillings and then also on the infrastructure that I showed you a few minutes ago. We’ll be able to quickly adapt that to this set of assets. All this really is possible because of the group of people we have. We’ve got a tremendous group of guys in place. Thank you.
[No Q&A session for this event]
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