Good morning, and welcome to the Third Quarter 2016 Williston Basin Acquisition Update for Oasis Petroleum Conference Call. All participants will be in listen only mode. After today's presentation, there will be an opportunity to ask questions. Please note this conference is being recorded. I would now like to turn the conference over to Michael Liu, Oasis Petroleum's CFO.
Please go ahead, sir.
Thank you, Chad. Good morning, everyone. This is Michael Liu. We're delighted to have you on our call. I'm joined today by Tommy News and Taylor Reid as well as other members of the team.
Please be advised that our remarks, including the answers to your questions, include statements that we believe to be forward looking statements within the meaning of the Private Securities Litigation Reform Act. These forward looking statements are subject to risks and uncertainties that could cause actual results to be materially different from those currently disclosed in our earnings release and conference call. Those risks include, among others, matters that we have described in our press release as well as in our filings with the Securities and Exchange Commission, including our annual report on Form 10 ks and our quarterly reports on Form 10 Q. We disclaim any obligation to update these forward looking statements. During this conference call, we may also make references to adjusted EBITDA and other non GAAP financial measures.
Reconciliations of our non GAAP financial measures to the applicable GAAP measures can be found on our website. We will also reference our current investor presentation, which you can find on the homepage of our website. And with that, I'll turn the call over to Tommy.
Good morning, everyone, and thanks for joining our call. It's been an exciting and important quarter and year for Oasis. We entered this year knowing that 2016 would be a pivotal year for us, increasing capital efficiency and paving the way to organic growth. With the acquisition of 55,000 net acres in the heart of the Williston Basin, our incredible strides on the operational side allow us to execute on a very accretive transaction. Our team continues to succeed in many different areas, including driving EUR performance higher, lowering well and operating costs, delivering increased margins through infrastructure and multiplying OnRx success through a bolt on acquisition.
As we've previously discussed, we continue to see incredible performance in our core areas with our current standard base completion design, which is £4,000,000 100 percent sands slickwater well. We'll continue to drill our core inventory position and coming into the Q3, as many of you know, we transitioned completions completely to our Wild Basin area. While we have shown our you our strong yet limited number of high intensity well performance results from the White DSU in Wild Basin, we now have significant additional early time production data results from numerous wells across multiple DSUs in Wild Basin with higher intensity completions. Although early time production, these wells have performed significantly above our expectations even while flowing at restricted rates. While our expectations were that Bakken wells in Wild Basin would be in the 1,200,000 Boe EUR range, They have performed well above that range and we now expect them to be in the 1,500,000 Boe range.
Our continuous optimization on completion design includes increased proppant loadings and focus on optimizing proppant dispersion across the wellbore. While data on these design improvements are already timed, based on the results we've seen in our well test as well as those from other operators, we are highly encouraged and expect higher average proppant loads going forward. On the well cost front, we've continued to reduce well cost down to 5,200,000 dollars on our slickwater base completion design. This number has moved down from $10,600,000 in the Q4 of 2014 and from $6,500,000 earlier this year. So the team has done an incredible job of improving on our efficiency gains.
The cost reductions over the past 24 months have been a combination of service cost deflation and significant efficiencies. The efficiencies have been derived through a focus of our operations in true development drilling mode. We are now seeing the benefits of long term planning and investment into infrastructure. We have talked for years about the benefits of large contiguous operated blocks and now we have that in our full development mode and you're seeing the benefits paying off with significantly reduced well cost. Importantly, these efficiencies should not be lost when the basin moves to higher levels of activity.
And on the service cost side, we're certainly nearing the bottom. The most eminent tightness that we see in the market is in the pressure pumping side of the business. As operators press proppant intensity on wells, there will be a natural increase in demand for pressure pumping that will be amplified if there is an increase in rig count. Oasis has a natural hedge on cost inflation related to pressure pumping as we have the ability to scale OWS back up to 2 frac spreads, which can cover up to a 5 rig activity level. In addition to basin leading well costs, we also continue to drive down LOE costs.
Although our costs are a bit higher in the 3rd quarter, we expect those to come down to recent levels and continue to go lower as we start growing our production again. Our infrastructure helps us deliver some of the best margins in the basin. Our team has been incredibly diligent and thoughtful in forming strategic partnerships with 3rd parties as well as through our creation of OMS. The combination of 3rd party and internally operated midstream assets covering oil gathering, gas gathering and processing, fresh water distribution and saltwater gathering and disposal gives us a huge competitive advantage operationally and financially. Specifically, we're excited to report that our Wild Basin infrastructure project is up and running ahead of schedule and on budget.
During the Q3, we did choke back the Wild Basin wells to manage production levels prior to that infrastructure becoming operational. These improvements in both well performance and capital cost compound to continue to drive improved capital efficiency as we make material strides in both single well IRRs and corporate returns on return on investment metrics. This momentum also transfers into our acquisition and all the work that our team has done on that front. The transaction is a unique opportunity for Oasis to continue to grow our footprint in the Williston Basin at attractive valuations. I will now turn the call over to Taylor, who will discuss the transaction in greater detail.
Thanks, Tommy. This acquisition is a great fit to our current asset base and adds meaningful production, core acreage and core inventory. We're excited about the opportunity to apply the stimulation techniques and operational efficiencies we've been utilizing in our nearby assets. We think that the knowledge that we have gained there over the past few years of the downturn can be quickly applied to this set of assets to extract incremental value in a short period of time. As you can see on Page 4 of the presentation, the acquisition includes 55,000 net acres and an estimated 226 gross and 113 net operated drilling locations.
The acquisition will increase our core inventory by 130 gross operated drilling locations for an increase of about 25%, all of which compete with our current inventory and are highly economic in the current price environment. Since the assets are held by production, we will be able to leverage leading edge completion technology and learnings from our current testing programs to maximize EURs in the most capital efficient manner. The inventory acquired is balanced with a meaningful current production base of about 13,000 barrels of oil equivalent per day. That will provide substantial cash flow to be used either to drill the acquired asset or accelerate our current asset base. As the asset has not been a recent focus of the seller, the PDP profile is favorable and should help mitigate reinvestment risk.
When looking at the deal from a metrics basis, we're paying about $60,000 per flowing barrel oil equivalent, which compares favorably with our recent trading levels at around $85,000 per flowing barrel equivalent. When backing out PDP value at $40,000 per flowing barrel, we're paying about $5,000 per net acre, which is favorable given the large amount of core acreage acquired. Given the geographic nature of the asset, we feel we have a unique edge to realize significant upside from the acquisition. While not a comprehensive list, we see 3 primary ways we can extract incremental value. First, we will use leading edge completion technology and proprietary data from the testing we are doing on our current asset to increase EURs on the inventory going forward.
The test we are currently doing with high intensity fracs, increased sand loadings, diverters and other techniques should provide analogs that can be directly applied to the acquired asset. 2nd, we should be able to drive the same operating efficiencies developed on our assets directly to the acquired assets. The advances that we have made in well cost and LOE reductions and the cycle time improvements across all phases of our operations will be applied directly to these assets. In addition, the infrastructure footprint that we have developed in the basin should provide cost benefits to the assets in the short to medium term. We believe we have a best in class operating team across our E and P, midstream and services business and the ability to apply those these core competencies to the acquired asset should be almost immediate.
3rd, as briefly mentioned above, we will be able to use the meaningful cash flow from the asset to either drill the acquired asset or accelerate our current asset. The asset is expected to generate over $100,000,000 of cash flow in 2017 at current strip prices, providing nice tailwinds and growth to our current corporate plan. We'll provide more color on future growth and capital programs during subsequent updates. With that, I'll turn it over to Michael to discuss the financing of the deal and Q3 results.
Thanks, Taylor. A few quick comments regarding the Q3. Tommy mentioned a significant positive operational momentum that our team generated in the quarter, including materially lowering well costs, achieving higher well productivity and increasing margins through operational start up, a strategic long term infrastructure. I will note that our production for the quarter was right in line with internal projections and while in line with street consensus, it was a bit light on the oil mix. The lower oil production level was a function of restricted rate production in the Wild Basin area, while we waited for infrastructure to start up.
Once again, this was not a surprise internally. Since the Wild Basin infrastructure started up around the beginning of Q4, we've averaged weekly production rates of over 50,000 BOE per day, which is higher than the Q4 consensus estimates. LOE was a bit higher in the 3rd quarter compared to recent quarters as well. Once again, this was no surprise to us, but was a bit of a surprise to the consensus estimates. The lower oil production rates and the higher cost due to trucking produced water in lieu of a functioning produced water gathering system combined to drive an approximately $8 per BOE rate in the 3rd quarter.
However, with the start up of the Wild Basin produced water gathering system and the higher rates of production in the area, the LOE costs in the Q4 will come back down in line with previous quarters. We plan to fund the deal with a mix of common equity and debt. The equity offering announced this morning will be used to fund the equity component of the deal. When taking into account the purchase price paid, the production and core inventory acquired and our planned financing structure, we expect the deal to be accretive on all metrics, I. E.
The balance sheet, near term cash flow and long term value. Finally, we discussed our 2017 plans on our last quarterly call. In August, we stated that we would continue to focus on spending within cash flow and that we would keep production flat in a $40 WTI world, we'd grow low double digits in a $50 world and grow mid teens in a $60 WTI world. Given the significant capital efficiency gains, we now think we could hold production flat in the sub-forty dollars world, grow low double digits in a $45 world and grow mid teens in a $55 world. We could not be more proud of what our team has done over the past quarter.
The acquisition will only add to our growth story. With nearly a quarter of our current production and core inventory, the acquired assets add to our significant base in the Williston. Given the depth of the inventory in the acquisition along with the significant cash flow generation, we will be prepared to grow the acquired asset at a similar or more aggressive pace in our current base. This will build to a growing 2017 and a further accelerated 2018. With that, we'll turn it back to Chad to open up the line for questions.
Thank you, sir. We will now begin the question and answer session. The first question comes today from Neal Dingmann with SunTrust. Please go ahead.
Good morning, guys, and congrats. Nice deal. Thanks. Tom, a quick question on your comment in here on the press release talking about not only well costs coming down, but about the £4,000,000 on the slickwater job on the techniques. I guess when you now look at kind of going forward, I know some of the peers you mentioned are doing even bigger jobs than that.
What's your thoughts about sort of how big can you get these jobs? And cost wise, how much would that push the cost if you do decide to push those completions a bit?
Yes. Taylor can probably add a bit more color, but we're kind of moving away from those what we call the base jobs now into higher numbers.
We've done
a couple of that are £9,000,000 and we've done some that are as high as in high teens. And so then it's just kind of optimizing off of that. And obviously, the call, I don't have the exact cost for each one, but it's higher proppant loads. And as I said too, it's getting a better spread across the wellbore, which we've got a couple of different ways we're doing that. And one is just some more stages, but it's just getting more distribution across the entire lateral.
Great. And then just focus area, Tommy, I know I was looking at that Slide 6. Obviously, this really boosts your what you guys deem your core acreage there. I guess the focus went the next few quarters at least just to stay now in that gross core operated area given now the additional acreage and locations?
For the most part, that's I mean, that's consistent with what we've been saying for some time, yes.
And then just lastly, as far as to Accelerate, is it more just price independent, is to stay within cash flow when you and Michael talk about that? How do you guys think oil has kind of been dancing around if we do get up in that mid-50s or high-50s, how do you guys think about maybe your plan?
As we get closer to 2017, it solidifies our plan. So a couple of things is we were kind of in the middle part of the year, a little bit further out, a little bit more uncertainty. As we get closer to the end of the year, Neal, we continue to hedge in. And so as we get more hedge protection, call it, with a $50 floor level or maybe a little bit higher on the swap side, we have a lot more comfort on where our cash flow is going to come out. And then given all the operational improvements and the capital efficiency that we've seen, we've got a lot more comfort going to a higher program because that, call it, staying within cash flow case is easier to do.
So I kind of talked about the cases that we laid out in August with kind of $50 $60 type oil prices. Now to get to those same level of activity levels and growth, it's probably $5 less on the oil price because of that capital efficiency that we're seeing. So incredible job by our team all around. It's making our play more and more economic, and that's allowing us to make decisions about growth. And we do see that we'll likely increase activity next year and start growing, especially in any pricing that's kind of around the current level.
Certainly makes sense. Thanks guys.
Thanks, Tim.
The next question is from Drew Venker with Morgan Stanley. Please go ahead.
Good morning, everyone. Good morning. Could you speak
a little bit more to the just the high level operating plan on the acquired assets? Are you expecting to develop the Bakken and Three Forks concurrently? And how many rigs you think you can run-in Wild Basin given infrastructure?
Sure, Drew. I don't think that the asset is any different than our current asset. This is a lay down on our current asset. So ultimately, all the inventory will be fungible with itself. And so, we're going to develop it in the same way we're developing the rest of our asset.
It's like our legacy asset. It's HVP. It's got a single well drilled on a lot of the DSUs. We'll go back in through those operated DSUs. And when we decide to go into them, we'll likely drill the rest of the wells out both Bakken and Free Forks.
So kind of full development mode on that asset. This does add inventory in and around that Wild Basin area. So the good thing is that the infrastructure in Wild Basin is now online. We can take the wells that we do have producing and kind of open them up the way we normally would as opposed to having them restricted. So we'll continue to watch how that goes.
We think that 2 rig program in Wild Basin makes a lot of sense as we just as we've said in the past, as we go past as we start to accelerate again, those rigs will likely go into our core areas, but maybe not in the Wild Basin. And as what you're talking about, it's some limitations on making sure that we don't overload our infrastructure in that Wild Basin area. But we've got a lot of core acreage outside of Wild Basin as well and we'll start increasing that level of activity in other areas.
Thanks, Tommy. And
do you have
a general plan on how much of your program will use these enhanced completions between now and 2017, even if that's somewhat preliminary?
Yes. So currently, all the completions we're doing are enhanced completions or high intensity, the 4,000,000 pound version of the frac, and we'll continue to do all high intensity completions even as the program picks up. Now the enhanced completions that Tommy talked about doing some of these 10,000,000 and even 20,000,000 pound fracs along with the other enhancements that we're testing, that will be a portion of our overall program. And as we have success with those results, we'll increase the portion of the program that's dedicated to that. It's probably in the order overall test of enhancements right now is in kind of 40% to 50% range of the wells that we're completing.
And then if we get positive results, we'll just increase that. Thanks for filling.
The next question is from David Deckelbaum of KeyBanc. Please go ahead.
Thanks guys and congrats on making the acquisition.
Just some questions. You said
you did add some inventory to Wild Basin. Can you quantify, I guess, what percentage of the core net and operated locations are acquired within Wild Basin? And can you, I guess, confirm what are the infrastructure that you have in place is sort of enough to take on the added inventory here?
So the way we're you can look at the map on Page 6 of the presentation. You can see where the assets lie around Wild Basin and the acreage blocks that are close in proximity to Wild Basin and that have the same type of recovery expectations in terms of EUR. It amounts to a little over 50% of the inventory we added. So we said 130 locations in the core, over half of those, we consider to be like Wild Basin and likely you could pull into that infrastructure.
Got it. Thank you for that. And then I just wanted to ask some questions on the Wild Basin type curves, very encouraging increases there. I know the white wells have been online. I guess there were 3 of those wells for some time.
These recent completions, I guess, they were all on restricted choke at the beginning. And I guess we can kind of see in the type curve plot that you put out that you can kind of see that it was opening up, guess, once you get out 60, 90 days. Are the future completions, I thought you heard you say, you won't be restricted in those on choke. Should we expect another shift in these curves? Or sort of what's giving you the confidence to kind of increase these kind of early in the history of these wells?
Sure. You
can you're referring to Page 6. And so if you look at the graphs on both the Bakken on the left hand side
of the page and the
Three Forks on the right, Tommy referred to the 1,550,000 barrel type curve for the Bakken. And you can see, as you said, actual production is rocking along a little under that and then you see an inflection and that does correspond to when we got additional facilities and we're able to open those wells up. So we'll see how the wells perform. As you said, it is early time, but outperforming that currently and we'll continue to monitor some of them and optimistic we'll continue to have that kind of performance.
Thanks, Taylor. Thanks, guys.
Thanks, Dave.
The next question is from Steve Berman of Canaccord. Please go ahead.
Thanks. Good morning and congrats. On the revolver side, I assume given the timeline, the reaffirmed borrowing base does not include these the acquisition assets. And if that's the case, do you anticipate asking for a redetermination before the next scheduled one in April?
Yes, Steve. You're right that that redetermination was based off of our legacy asset position. What I'd say is that on a theoretical basis, our reserves actually were more positive than this fall. Margins were better. There's a chance that the theoretical borrowing base actually probably went up even on the legacy asset.
And then with this asset, you're right that that borrowing base level could continue to go up. We haven't gotten there yet in terms of asking for that, but that's certainly something that we could do. We still have significant amount of liquidity. So we don't necessarily need a higher commitment level than what we've got. So we'll work through that here in the coming weeks.
Got it. And then you were talking about the mix before given what Q3 was 81% oil and the acquired assets are sub 80%. What should we assume going forward in terms of an oil and gas mix on the production side?
Yes. I think that you can take that 81% in the 3rd quarter and use that as kind of a good level for now. Obviously, as our if our program was just in Wild Basin, the gas mix would increase or the oil mix would continue to go down a bit. That area is kind of a 70% to 75% oil mix. So but as we start to accelerate again and we start putting rigs in areas outside of Wild Basin, they'll start kind of balancing back out.
Most of our other areas are more in a more of a 12% gas cut or 88% oil type areas.
Got it. And then one more quick one, if I could. Just to be clear on Slide 6, the core inventory locations you're acquiring, That's just the core. There's others in the extended core and fairway from what you're buying that are not in those numbers. I just want to clear on that.
You're just saying
what the core? Correct.
Okay.
Correct. There's actually, if you look on Slide 6, we talked about 130 gross operator locations in the core, but the total was 226. So you've got another gosh, another 96 locations that are outside the core, as you said, are in the extended core in the fairway. And you can see that on the map on Page 6, kind of where that acreage lies and all that we feel like it's in good areas as well.
Okay. Perfect. Thank you, guys.
Thanks.
The next question is from Kyle Rhodes with RBC.
Just any more details you can give on the timeline of the deal? Just something you guys have had some unsolicited offers to SM on for a while or just maybe some more color there?
Yes, we can't comment about that right now. Okay.
And then just as I think about 2017, is the governor on 2017 production growth still spending within cash flow or does this equity deal kind of change the willingness to outspend?
Well, what we're discussing right now is still plans within cash flow. The good thing is that we will have we've done a convert deal that's lowered to interest costs. We've done this deal which brings on a lot of cash flow. It doesn't there's not a need for a large G and A increase and there's less interest costs associated with the deal. So you actually generate quite a bit more cash flow.
So it's accretive to kind of that cash flow side of things. All that will get reinvested into the business, which should increase the growth rate. You're still as we've discussed, you're seeing very strong growth rates within cash flow. So the need to outspend to increase that growth rate,
we'll have
to make that decision, but it doesn't look like we need that. We're going to show some very strong growth rates within cash flow.
Got it. Thanks. And just one kind of final one for me. On the EUR increase in Wild Basin, did the GOR stay constant to that 2,500 rate? I know there was in the slide deck now.
Just curious if there was any increase to the gas coming in the new EUR?
It's the same assumption on GOR on that. It's just the whole curve oil and gas moving up proportionately.
Great. Thanks guys.
Thanks, Hugh.
The next question is from Kashy Harrison with Simmons and Piper Jaffray. Please go ahead.
Good morning and thanks for taking my question.
You bet.
On a higher level, do
you expect to continue to play
the role of natural consolidator in the Bakken? And do you see more opportunities kind of in the your core area?
Yes. We've consistently said since the very beginning that we'll always look for opportunities to bolt on in and around our core positions. It's natural leverage for us. And it's we're obviously very good at it. So I think as you see, I mean, what you're seeing is some portfolio shift with people and that may create some opportunity for us, but we'll just you just got to play it as it comes.
Okay.
Thanks for that. And then can you help us think through what the average Bakken and Three Forks EURs look like now in the core when you take the weighted average of the new Wild Basin cores and then you combine that with the older Indian Hills and Algiers curves?
Yes. So on the legacy asset in our historic inventory, it was kind of fifty-fifty in terms of Wild Basin and outside. And so with we kind of had just over 1,000,000 MBOE type curve in the core. The Wild Basin size was 1.2. And so that implies that all the rest of the core was more than $850,000,000 to $900,000,000 type range.
That doesn't change. Wild Basin did change up. So you can take that blended effect there. And then as you think about the acquired asset, as Taylor mentioned, half of that core inventory is in Wild Basin. So it's a pretty even mix.
It's about a 28% overall increase to our core acreage position. So and a pretty even split between kind of that Wild Basin type performance level and the other kind of core performance level.
That's actually super helpful. And then last one for me. Can you walk us through just where you think well cost could traverse through over, call it, the next 12 to 15 months as you think through just the potential for forward efficiencies and how that might be potentially offset by some service cost inflation?
Yes. Obviously, we've made some big moves on well costs this year and the move down from in 1 quarter from 5.7 12% drop. So we've made some huge strides. A lot of that this year has been on the efficiency side of the business. We think we're probably, I think as Tommy mentioned, kind of near the low end of the cycle on the service side, not a lot of room to give there.
So what we do pick up will likely come on the efficiency side of the business. That being said, we think we can continue to get more efficient. You're just not going to see as huge jumps as we've seen over the past 2 years, but we'll continue to work on improving
it.
All right. That's it. Thanks, guys.
Thanks. Our
next question is from Gail Nicholson with KLR Group. Please go ahead.
Good morning, everyone. Just kind of to piggyback on the well cost. Your drilling days continue to improve quarter over quarter. You knocked off another half a day down to 13 days on average in 3Q. What are you from a leading edge standpoint, what's the best well to date from spud to rig release?
And do you think that's something that you think you can repeat on a go forward basis as you continue to improve efficiencies?
Yes. We like you said, we continue to move those efficiencies and the cycle times down and a half day this quarter. We've done wells in as little as like 10 to 10.5 days, but that's getting everything aligning. So we'll like I said, I think we'll continue to make strides on efficiencies and you just won't see as chunks as you've seen over the past couple of years, but you'll continue to see going in the right direction.
Great. And then when we look at the changes or further enhancements in the completion design, I'm assuming when you guys talk about your 2017 growth expectations based upon the different commodity deck assumptions, that is not baking in any potential improvement for more profit loading, correct?
Yes, correct. At this point, we're just modeling our base jobs. And as we get confirmation of kind of uplift we'd get from bigger jobs at that time we'll incorporate it.
Okay, great. Thank you.
Next question is from Ron Mills, Johnson Rice. Please go
ahead.
Go ahead, Mr. Mills. Perhaps your line is muted. Do you have the floor? All right.
Once again, Mr. Mills, we're unable to hear you. We'll move on to our next question. That is from Jason Smith with Bank of America.
Hey, good morning everyone and congrats again.
Thanks.
I know we've covered a lot of ground here.
So just a quick one for me. What does the growth profile of flat at $40 and double digit growth at $45 within cash flow assume for the completion of your remaining DUCs? I guess how does that play into your plan to potentially add rigs?
Yes. In the $40 world keeping production flat, that's keeping the 2 rigs going. So it's really not assuming any DUCs. So the DUC levels kind of stays flat. As we think about the 2 kind of growth scenarios, either kind of low double digits or that mid teen type growth rates.
Those would include some component of DUCs, but also some component of rig acceleration or new rigs coming into the basin. Those aren't perfectly modeled in, but it is a combination. What we said about the DUCs is that it does give you an opportunity to kind of marry the timing that you start spending some of your capital with production increases so that as you start to think about bringing on rigs now that we're in all development mode, it does take a little bit longer for when you first start drilling to when you bring on that first well on the production because you're drilling out a number of wells within the DSU before you complete them all. So the DUCs actually allow you to start completing wells while you're going through that drilling process and kind of marrying that the time that you're starting to spend capital with production coming online.
Got it. Thanks, Michael. And then
I guess just one quick follow-up. Obviously, you guys added to the hedge profile. Are you comfortable now with where you stand on 2017 or
is that something you want to is there
a certain percentage you want to target at this point for next year?
Yes. I think we were pretty comfortable with where we were on our current asset, kind of get into that trying to get into that 60% range by year end. And then we would build kind of after that. And so current asset, we were pretty comfortable. And then as you add the new asset, obviously, we'll need to get to that same level with kind of the combined entity.
And we think we're on track to do that.
Got it. That's all for me. Congrats again, guys. Thanks.
Yes. Thanks.
The next question is from James Sullivan with Alembic Global Advisors. Please go ahead.
Hey, good morning guys and congrats again on the deal. Just a quick question here on the can you help me with on the acquired acreage where most of the production is located? Is it principally on the blocks that Tuck into Indian Hills and Wild Basin or is there a lot of it over by the state line and then in Montana?
It's you got a bit of a mix across the position. There's the recent drilling in the past few years, like everybody else has been a little more focused in the core. So you got some little bit more flush production in the core areas. But in general, it's probably a little bit more East, but some across the whole position.
Got it. I guess what I'm getting at is that, obviously, this stuff is going to try to tie into your the infrastructure position you guys are building out there in Wild Basin. I'm trying to think about whether it'd be fair to think of $8,000,000 or $10,000,000 of gas on a net basis to be putting in, plus you guys have some that you already have. And if you gross it up, kind of where you are in terms of filling out that 80,000,000 cubic feet and when you might need in the growth scenario, that you guys outlined when you might need another plan or are you guys just well clear of that?
Yes. Like we've talked about with the plant coming on, we think that you fill it up something like late next year into 2018. So this gives us some additional volumes in the area that we'll contemplate tying into the
tie in. Yes. No, it's not a problem to have. All right. Thanks for that.
Just one last one, if you can help me. This is a little specific on the accounting side, but can you allude the cash in cash out for the quarter? I have you guys raising $300,000,000 from the convert and spending $375,000,000 on the tender $370,000,000 on the tender to retire debt. The revolver borrowing was $160,000,000 I guess according to your disclosure and I estimate you guys being roughly cash flow neutral for the quarter, but the cash balance only rose a little bit $5,000,000 or $6,000,000 I guess. So there seems to be $80,000,000 or $90,000,000 unaccounted for there and I assume that's not all working capital.
Am I missing something in there? Can you help me
with that? Yes. We can follow-up with you somewhat afterwards as well, but there's cash interest and a couple of other kind of working capital items that make that difference.
Okay, great. Thanks. I'll follow-up. Thanks.
Our next question is from Gregg Brody with Bank of America Merrill Lynch. Please go ahead.
Good morning, guys.
Good morning.
Just as you think about the asset, I'm just trying to understand what the how the relative production cost base looks like? So is there a difference in the decline rate of the assets you purchased versus your own? And are there big cost differences on the operating side that are notable?
Yes. So the like talked about in the script, when you look at the production profile of these assets, they haven't been the seller acquired as active in development here over the recent past. So decline profiles are maybe a bit less than what we're looking at. So, that's favorable. And so we think that bodes well for us in terms of what we got to do for production maintenance going forward.
And then on the margin side, it's very similar to our asset kind of overall at what we cost, etcetera. We think that we'll be able to, 1, scale back into our system very effectively, and we think we can manage this asset with a very similar margin overall to our current asset.
Did you pick up any DUCs with the transaction or?
There's some non op DUCs, but not on the operated side.
And then just maybe bigger picture, you funded this with a little bit more equity than debt. You did the convert a few weeks back. How are you thinking about leverage going forward? How are you managing that? And just a bigger picture view would be helpful.
Yes. We feel very comfortable with where the capitalization is and where we are going forward. We've always said since our IPO that leverage long term at a long term oil price normalized oil price, we'll shoot for kind of a 2 times on a longer term basis. But we think with kind of the productivity gains that you see here, we're in a good shape to get to kind of our targets on an organic basis.
And then but in that, is there with the convert, I know you have the option in the future to if it's converted, you can actually use cash or common stock. How do you when you think about that today, what are you anticipating?
Yes. I mean, you'll actually see in those convert docs that our assumption is that we'll settle this. It's like a piece of debt more than it is equity. So we'll settle that on a net share basis, which means that we'll settle the principal and cash. And that's kind of in there and that's how we account for it.
And that's the final one for you. Just the midstream side, this potentially gives more brings more volumes into the system. Is monetizing the assets still on the table today? Obviously, depending on price, but are you still thinking about that?
Okay. At this point, we don't have a need for that. That being said, we'll always take a look at it. There's a large arbitrage in terms of valuation between midstream and E and P, which you've seen in the past. If we see that, we're always willing to take a look.
But that asset gives us a lot of operational efficiencies, synergies, huge for our cash margins. It's a big advantage for us. So we love that asset.
Makes a lot of sense. Thank you for the time guys.
Okay. Thanks.
Next question is from John Nelson with Goldman Sachs. Please go ahead.
Good morning. My questions have all been answered. Thanks.
Thanks, John.
Thank you. We will move on to Ron Mills with Johnson Rice. Please go ahead,
sir. Hey, guys. I'm back. A couple of questions. Hey, Ron.
Glad to have you back.
Yes. On the growth numbers you gave, Michael, kind of low double digits at 45% and mid teens at 55%. Is that on your standalone or in fact is that off the pro form a volumes? How should we think about that?
Yes, it's a great clarification, Ron. That is all off of our kind of our legacy asset position. So think of that as kind of a 3rd quarter update without the acquisition. And then as we think about the acquisition, it adds about 25% production on top of what we're currently producing. So call it 12.5 versus our 50 a day.
And like I tried to mention at the end of that commentary today is that we'll likely grow that over time at a similar pace to the way we're thinking about growing our current asset. The only nuance there is that with similar margins but less interest costs and less G and A costs on that asset, you actually get a little bit more cash flow. So I said that you keep kind of a similar growth trajectory or maybe a little bit faster. So all positive for us.
And because the properties are kicking off, I think Kyo said $100,000,000 plus but you can kind of assume 25 ish percent of what our numbers are. Is that a built in way for you to add a 3rd rig and still remain within cash flows because and even then is $100,000,000 is how is that way too high in terms of what a rig year would cost you on a net basis?
Yes. Our $100,000,000 it is about a rig or maybe a little bit less depending on working interest of those and where our well costs are going. Obviously, it's going to be less than $100,000,000 per operated rig. But we are looking at kind of on a same, same basis, you probably would have a rig running on that asset compared to where we're at on our current asset.
Okay, good. And then in terms of the OMS in this property, are any of the SM volumes that are subject to acreage mitigation with other systems or can they be moved over to your water basin system?
So we're still, Ron, we're still working through all that contracts. There is a couple of other parties actually, depends on it's gas or oil, but we think there is going to be some flexibility to move volumes around, but we got to work through all that.
And to the extent you can move some volumes around with your existing system running on that $80,000,000 EBITDA run rate, and I think you all talked about once a while basin is fully up and running then that your OMS could be somewhere in the $140,000,000 range. Jason, if you can add some lesser volumes, does that pull some of that EBITDA a little bit sooner because you get those volumes before maybe some of your drill gloves?
Yes. Not only would you potentially get some of that sooner, but you'd also kind of increase kind of the top end, right? Some of that would just be incremental, especially on the water side. We're not we don't have a lot of capacity limitations there and connecting wells to our large system incrementally is actually relatively cheap.
Okay, great. And then one last one, just on the DUCs. You're down a couple of DUCs, I think, from your last update call. Are you still running at about kind of 2 times, which you think a normalized DUC inventory is? And if you added the 3rd rig, what do you think a normalized DUC inventory would be relative to the 80 you have today?
So, we said that the 2 rigs that we've got some excess capacity in this drilling full spacing units, you obviously need a bigger pad of wells because of the time to drill out the spacing unit and get them frac ed online. And you think about it as something like the it's somewhere in the 10 to 20 per rig range. And so it is going to bump up. With 2 rigs, we've talked about having maybe 40 or 50 something wells like that, that you could you'd have at your disposal as you bump rigs up, that's going to come down relative to the 80 range where we are currently.
All right. Thanks again and congrats on the transaction.
Thanks, Rob.
The next question is a follow-up from Gail Nicholson with KLR Group. Please go ahead.
Just in regards to the 2017 growth scenarios, does that assume a similar decline rate that you guys have achieved in 2016? Or are you assuming a shallow decline rate as your production base ages into 2017?
Yes. Our year over year between 2016 2017, the decline rate is going to be coming down a touch, but not drastically.
Kath.
Ladies and gentlemen, this concludes our question and answer session. I would like to turn the conference back over to Tommy Nusz for any closing remarks.
Thanks. As you can tell, Oasis has executed against this strategy, creating long term shareholder value through improving capital efficiency on our standalone asset, purchasing a position that's a great fit to our current asset, allowing us to capture the benefit of our operational performance across incremental core inventory, positioning the company to grow in a low commodity price environment, and I think we've done a great job at that. We appreciate your participation in our call today. Thanks.
Thank you, sir. The conference has now concluded. Thank you for attending today's presentation. You may now disconnect. Take care.