Good morning. My name is Frank, and I will be your conference operator today. At this time, I'd like to welcome everybody to the Q3 2015 Earnings Release Operations Update for Oasis Petroleum. All participants will be in listen only mode. After today's presentation, there will be an opportunity to ask questions.
Please note this event is being recorded. I would now like to turn the call over to Michael Liu, Oasis Petroleum's CFO to begin the conference. Thank you. Mr. Liu, you may begin your conference, sir.
Thank you, Frank. Good morning, everyone. This is Michael Liu. Today, we are reporting our Q3 2015 financial and operational results. 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 earnings 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 we will also make references to adjusted EBITDA, which is a non GAAP financial measure. Reconciliations of adjusted EBITDA to the applicable GAAP measures can be found in our earnings release or and on our website. We will also reference our November investor presentation, which you can find on our website. With that, I'll turn the call over to Tommy.
Good morning, and thanks for joining our call. Given the current environment that we're living in, I can't say enough about what the Oasis team has accomplished in a trying year with both oil and gas trading at depressed levels. The team took the right steps to position us for 20 15 and has set us up for a successful 2016 even if we don't see a more bullish commodity backdrop. We are proud to report that we have exceeded expectations on all fronts this quarter. We delivered a beat on production, differentials, LOE, G and A, EBITDA, well costs and cash flow, and that is with WTI averaging $46.43 for the quarter.
Also, earlier this year, we felt like that we were positioned to be free cash flow positive in 2016 with WTI at $60 per barrel, and now we are setting up to be free cash flow positive at $50 a barrel WTI. Both scenarios exclude infrastructure capital for OMS, which Michael will discuss later. Our drilling and completion program in 2015 2016 continues to be basically the same as our original plans, but with a few changes. We originally set a plan in 2015 to complete about 60% of our wells with either slickwater or high intensity stimulation, and that has now progressed to north of 70% in the second half of the year. Results from our high intensity completions continue to exceed our expectations and have led us to move more of the program in 20 16, in fact, greater than 80% high intensity.
On the drilling side, we intended to run 5 rigs throughout 2015 to complete our program, but our drilling team has knocked down the drilling days such that we were able to ramp down to 3 rigs midyear and still execute on our original plan. Those rigs have started to transition to Wild Basin now, which is in the eastern part of our Indian Hills project area and is the deepest part of the Williston Basin. This is where OMS is currently putting in our gathering and processing infrastructure. The infrastructure is expected to be fully operational in the fall of 2016, which coincides with when we plan to bring on production from the wells in that area. On Slide 13 of our posted presentation, you can see the progress we're making on our $80,000,000 a day gas processing plant, and we will start construction of gathering lines for oil, gas and produced water as we get into 2016.
We expect that this project will be highly accretive to our execution plan in Wild Basin. At this point, our 4th quarter plan has us completing a few less net wells compared to the 15.4 net operated wells we completed in the 3rd quarter, and we're hedging against some weather impacts, winter weather impacts. So we've essentially maintained our flattish production volume guidance. Given continued winter operations in the Q1 of 2016, we expect similar production compared to the Q4 of 2015, but volumes should ramp up throughout the year and be a bit back end loaded with the completion of the Wild Basin plant. So volumes exiting 2016 are expected to top volumes exiting 2015 as the plan is currently laid out with the year being relatively flat to a bit up if everything goes as planned.
With similar production levels year over year coupled with both lower operating costs and low well costs, we're well positioned in 2016 for $50 oil. Project level economics in the core range from 25% to 40% at $50 WTI. In light of those economics and the downside protection afforded by our hedge program, we continue to layer in swaps during the Q3 of 2015, providing protection in 'sixteen for about half of our production and we expect to lay in additional positions as the market allows. With that, I'll turn the call over to Taylor for more operations detail.
Thanks, Tommy. The Williston Basin continues to be the premier oil basin in North basin. With around 500,000 net acres across the play and production north of 50,000 barrels of oil equivalent per day, Oasis is well positioned. We believe you must have both great assets and great people to succeed in this environment. And our performance in 2015 is further evidence that we have both.
Our team further reduced our well cost this quarter. And as a result slickwater completions in the quarter now cost $7,400,000 which is less than 10% over our base well cost to complete our wells. In Indian Hills, we are now drilling more than 30% faster than our 2014 average. Our current wells are being drilled under legacy contracts, so we will have a chance to further reduce drilling costs at the end of the year when these contracts roll off. Remember, we've only paid $3,900,000 of rig termination fees because we laddered our drilling contracts to provide the flexibility to drop rigs in a down cycle.
We were also able to drop 3rd party frac crews at the beginning of the year without penalties. And since that time, OWS has handled 100 percent of our completions. Because we strategically managed the program and did not spend the capital to complete all of the wells we drilled in the Q1, we have a backlog of wells waiting on completion that gives us flexibility depending on which direction oil heads. As mentioned in our press release, we expect to complete around 80 gross operated wells this year with 60% being stimulated with high intensity fracs. Results from both slickwater and high volume proppant continue to significantly outperform our base wells, which is why we are shifting our program to over 80% high intensity fracs in 2016.
We completed 100% of our wells in the core in the Q3 and the remainder of the wells scheduled to be completed this year are in the heart of the play. Last quarter, we mentioned that we plan to test all sand slickwater completions in the quarter. And we recently completed 3 tests in Indian Hills. These wells are in early flowback, but if their results are the same as we have seen in Montana, where production with and without ceramic are very similar, then we will apply this technique more broadly in the core. The benefit would be an additional savings of $500,000 per well.
These savings are not baked into our plan yet nor in our $7,400,000 well costs that I spoke to earlier. While we have driven down well costs while we have driven well costs down by 30% from the end of 2014, we remain confident we will see further well cost reductions through both improvements in operational efficiency and service cost reductions. Our operational improvement accounts for just under half of our cost reduction, while the remainder has been derived from 3rd party services and materials. Accordingly, we anticipate that much of the cost improvement is more structural in nature and should remain when prices rebound. We do not yet have a Board approved budget for 2016, but due to lower well costs, we currently expect to spend less than $350,000,000 in drilling and completion capital next year, which should result in flat to slightly going production for the year.
Additionally, it is especially encouraging to note that these cost reductions and performance enhancements extend to our acreage outside the core. While we currently have no plans to drill outside the core, we believe we have a considerable amount of additional economic inventory should prices tick up a little. Last quarter, we talked about our Montana position specifically as it related to a slickwater completion test with 100% sand where we could deliver a double digit return at $60 WTI. With the lower well costs we are experiencing, we also see double digit returns for the extended core at around $55 WTI and in Cottonwood around $60 WTI. I will close out my remarks with a discussion on LOE, which we have driven down to $7.67 per BOE, a reduction of $0.59 over the 2nd quarter.
This improvement was driven by 2 things. 1st, an increase in produced water volumes being transported on OMS pipelines. We exited the Q3 with 75% of our produced water on gathering on our gathering system, up from 40% at year end 2014. It was also driven down by lower workover costs due to improved operational efficiency and run times on our wells. LOE per BOE may increase slightly as we head into the winter months.
However, as the team is setting targets for 2016, I expect that we'll be able to find ways to keep the momentum that we have established during 15. All told, it was a tremendous quarter for Oasis. We've done a great job of keeping our focus on improving capital efficiency through solid operational execution. We have recognized several opportunities to improve our results through innovation, and we will maintain a flexible approach to assure that we capture all opportunities for value creation. In closing, I want to recognize the diligent work and innovative approach of our team in this tough environment.
They have delivered great performance even with low commodity prices and have set us up for the future. With that, I'll turn the call over to Michael.
Thanks, Taylor. Oasis delivered another incredible quarter as our E&P, Midstream and Well Services businesses all posted impressive results. As a company, we were again able to operate the business cash flow positive this quarter with adjusted EBITDA of $189,000,000 Our Midstream business delivered $20,500,000 of adjusted EBITDA primarily due to gathering a higher percentage of Oasis' produced water and another quarter of high fresh water sales. We now anticipate that OMS will generate over $60,000,000 of adjusted EBITDA 2015, which significantly exceeds our original projections of approximately $40,000,000 coming into the year. The midstream business continues to improve as we continue to utilize our large scale system towards its full potential.
As previously discussed, we are exploring avenues to monetize a portion of OMS and we seek to bring in external capital to fund our 20 16 infrastructure program of approximately $150,000,000 Most of this capital will be focused on the Wild Basin infrastructure project Tommy we believe we're in a significantly we believe we're in a significantly stronger position to maximize the value of this rapidly growing business while maintaining control. We exited the quarter with liquidity of $1,350,000,000 And in the 1st week of October, we announced that our lenders completed their regular semi annual redetermination of our borrowing base resulting in an unchanged commitment level of $1,525,000,000 CapEx came in lighter than expected during the Q3. As well costs came down rapidly throughout the year, actuals came in below engineering estimates and the true up of about $50,000,000 led to our lower CapEx during the Q3. Importantly, this does not change our year to date capital expenditures of $520,000,000 and we'll still see full year 2015 CapEx come in at or under our current $670,000,000 capital plan. With CapEx down 50 7% in 2015 compared to 2014, volumes are still projected to grow by approximately 10% year over year.
Another great trend this year has been our oil differentials, which have fallen from about $8 per barrel in the quarter of 2015 to below $5 in the Q3. We are now expecting our differential to remain between $4 $5 before the Q4 of 2015 and we are currently estimating a $5 differential for our 2016 plan. Finally, our team exceeded production and we raised full year guidance again this quarter, while lowering well costs, LOE, G and A and differentials. Our all in operating costs are now down 35% from $33.61 per BOE in 2014 compared to $21.78 in the Q3 of 2015. With all of the hard work from of our employees, we have quickly repositioned Oasis to be able to continue to grow year over year and make solid returns at a much lower oil price in 2015, 2016 and beyond, while continuing to spend within cash flow and preserve our strong liquidity position.
I'll now turn the call back to Frank to open the lines up for questions.
Thank you, sir. We will now begin the question and answer session. First question comes from Neal Dingmann from SunTrust. Please go ahead, sir.
Good morning, guys. Say, just your thoughts, you mentioned about going to obviously the Wild Basin area. I'm just telling me your thoughts about looking at Eldridge and some of these other areas, if you would consider going to any of those areas in 2016?
Yes. Neal, we're right now transitioning to where all 3 rigs will be in Wild Basin in preparation for the start up of the plant in the second half of the year. Later part of the year, we may have a few in some of the other areas from a drilling standpoint. But keep in mind that with the drilled uncompleted inventory that we have, we've got a number of wells outside of Wild Basin, primarily in Indian Hills, that we'll be completing as we go through the first half of twenty sixteen. But a lot of this drilling is focused in Wild Basin just so that we can adequately start up the plant in the second half.
No, makes sense. And then just one last one. Obviously, liquidity and Michael mentioned about not having obviously outspend much of an outspend issue, if any. There's no issues there, but your thoughts about if you would look into monetizing the midstream services anytime soon?
You mean the OWS business, the frac services business or OMX? Yes.
I'm sorry, the OWS.
Yes.
We've done a really good job with OWS. It's been a great business for us. Monetizing that into this market would be challenging. I think I don't think that we would receive the value in the flexibility in that business and our ability to control costs all the way through the value or the supply chain. So I think it's much more valuable to us at this point than it is externally.
Yes. I think I agree at this point. Thanks, Tommy.
You bet.
And the next question comes from Ryan Oatman from Cowen. Please go ahead, sir.
Hi, good morning.
Good morning.
In the August presentation, Slide 11 suggested that the current IRRs were similar with enhanced completions at $55 NYMEX as they were all the way back in May of 2015 with $70 NYMEX. Your slickwater well costs have come down about 5 percent quarter over quarter. The differentials are narrowing. I was just wondering if you could update that comparison for us and how the current returns compare to those you're seeing in May of last year?
We don't have that in front of us, Ryan. I can get together with you afterwards to go in a little bit more detail. But IRRs continue to improve from a number of standpoints. 1, as we see continued outperformance on those wells, We're getting better IRRs. Well costs have come down dramatically.
LOEs come in dramatically. Differentials have come in dramatically. So all the different pieces have contributed to it. I don't have exactly the breakout of what contributed what there. But overall, everything is contributing to those IRRs getting improving even at lower pricing.
Yes. Keep in mind that
the end of
last year, well cost for these high intensity completions were running somewhere around $10,500,000 and that now is $7,400,000 So a big move in initial cost along with all the other components coming down as well.
That's helpful. And then you guys have mentioned that the slickwater well costs that used ceramic, the cost for those have come down. Is it the ceramic cost itself that's decreasing? And then if that's the case, how would that change the math in terms of potential savings from shifting from, say, £4,000,000 of ceramic to £9,000,000 of sand?
So it's pretty even. It's across the well. It's not just material. So there's a combination of things that have driven the cost down. There is, as we're showing about of all the cost savings so far, about half of that have been service reductions.
And then the other half has really been around efficiency. And so we've gotten much more efficient in terms of cycle times, eliminated downtime and really improve the well cost from that standpoint. And then like I said, the other half being service and material side of the business.
That's very good. And then one final one for me. I noticed in the back of the presentation, the illustrative high intensity EURs, looked like it was about 850 MBOE last quarter. It looks like there's now 2 curves there, 1 at 875, another at $975,000,000 Just wanted to see kind of what drove that change and what your latest thoughts are for EURs? Thanks.
Yes. It's just a reflection of what we're seeing in the core performance. And if you look back on Page 10, you can see for Alger and for Indian Hills that the wells are performing at those higher ranges. So we've just added that to reflect the performance that we've actually seen in the wells.
And our next question comes from Tim Rezvan from Stern AG. Please go ahead, sir.
Hi, good morning folks. I was hoping to just clarify, I guess, some of the comments you've made earlier on 2016 to make sure, I guess, we understand your thought process. Is it true, I guess, base case level of activity, you talked about $350,000,000 spending to keep production flattish and be roughly free cash flow neutral? Is that kind of what you're thinking? And then I guess on top of that, this back ended skewed to production growth.
Is that kind of a fair assessment of what you've described?
Yes, Tim. That's pretty much what we're talking about, 350,000,000 dollars of D and C capital. We'd spend within cash flow at a $50 oil price, that would keep production flat to growing slightly. And then what Tommy mentioned was that because of weather, we've given guidance on the 4th quarter that volumes may come down just a touch and you might see that at the beginning of next year, but then you'll have a ramp towards the back half of the year Also with that Wild Basin asset and infrastructure project coming online, it may be as opposed to the flattish production you've seen this year, it may be a little bit more skewed next year.
Okay. Okay. And then I guess if we take you talked about the OMS monetization. It sounds like you're moving down that path. If you don't get something done, does that imply a $150,000,000 kind of gross spend for 2016?
Yes. If we did nothing next year on that OMS asset, that would mean add a $50 DAC, $115,000,000 of outspend. Obviously, we have the ability to do that under our liquidity, but that's not our preferred route.
Okay. Okay. Just wanted to clarify that. Thank you.
Thank you.
And our next question comes from Van der Aynvak from Wunderlich. Please go ahead.
Hi, guys. I just had a few questions on the production guidance. I was wondering how much of the winter effects are baked into the 4th quarter numbers. I'm wondering if the winter is a little milder than expected. Should we assume that you guys will be above that range?
And just generally in terms of production guidance, I know the high intensity wells have been really great and you guys have been coming in above guidance pretty consistently. Do you feel like these wells can still surprise you from here? Or do you think that the production guidance is going to be a little bit more within range going forward?
So first on the production guidance going into the Q4, it there's 2 things. 1, we do have a few less wells that we're going to complete in the Q4 relative to 3rd quarter, but we're also factoring in normal winter conditions that we see and especially get that usually December timeframe and it can be wildly variable. So if you have a really warm winter, we could do a little better, but really cold, you could drive the other way as well. With respect to the high intensity completions, we what we model is 30% uplift on average. And clearly, we're seeing better performance in that in some of the areas.
So we're optimistic that we'll continue to see that outperformance, both in the areas where we're really going to be doing the work in the core, which is Indian Hills and especially Wild Basin next year.
Okay. Great.
One of
the things we figured out is we're not very good at predicting the weather. And so it's kind of planning for if we have more precipitation or if it's warmer than normal is it's actually better when it's colder. If we're kind of bouncing around where it's warmer and it doesn't stay frozen and with precipitation that could be problematic for us. But as always, we kind of hedge a little bit on against weather because we just don't know.
Okay. Thanks, guys.
And our next question comes from Brad Carpenter from Cantor Fitzgerald. Please go ahead.
Hey, good morning guys and congrats on the nice quarter. I had a few questions on OMS. I was looking at your guidance of over $60,000,000 EBITDA for the full year and that to me suggests the sequential decline in 4Q. I'm just curious what are the drivers behind that implied lower 4Q number versus
3Q? I'm sorry, Brad, 4th quarter, what was lower?
Sorry, the so the OMS guidance of over $60,000,000 on EBITDA for the full year, just looking at the 1st 9 months, I'm getting to a lower sequential 4Q number. So I was hoping you could just talk about the moving parts behind that.
Sure. One of the things that I mentioned was that the Q3 and really the second quarter was a couple of things. 1, we were getting more of our wells connected to the system on the produced water side and so that drove some of the outperformance. The other part of it was there was a high amount of freshwater sales, but OMS doesn't supply 100% of the fresh water in all areas to the company. In some areas we go with 3rd parties.
And so in those areas you're not going to make as much money for OMS. So that freshwater sales may not be as high going forward.
Got you. Okay, that's helpful. Thanks. And then looking at the Wild Basin project, you guys have laid out that $150,000,000 of CapEx for 2016 2017. I was hoping you could talk about what I know it's a ways out, but maybe full year 2017 EBITDA might look like for the project assuming everything goes to
plan? Yes. If everything goes according to plan and you get to call it the end of 2017, all that infrastructure should be running fairly full capacity by then. That asset could produce over $60,000,000 of EBITDA on its own.
Okay, great. All right.
That's very helpful. All right. Thanks, guys.
Thanks. And the next question comes from Ron Mills from Johnson Rice and Company. Please go ahead.
Good morning. Couple of questions. Just on the DUC breakdown, I know you have 87 and I think you'll probably stay around there for year end. But are most of those now located in Indian Hills and in Alger areas, I. E.
The core or some still spread across some of your other areas?
So you're right. We've got 87% at the end of this quarter and we think we'll be at low 80s by end of the year. So we'll work down that wells waiting on completion through the end of this year. When you look at the total, you've got right now about 20 of those wells that are outside the core, but they're in close proximity. And like we've said before, as we move forward, all those wells will give us the flexibility to accelerate a bit if we get into an improving oil price.
And are those ducks or are those outside the core, those are in areas nearby existing gathering systems and such where those would be relatively easy to bring on?
Yes, it's a great point. There's quite a few of them that are in fact the majority are in Eastern Red Bank and we've got full infrastructure in and around that area and that's really one of our better performing areas. In fact, we've got that highlighted in the presentation this quarter on Page 12.
And Ron, that's a great point. In terms of the most of most of that inventory actually has very good infrastructure. So it's not something that we would have to wait for additional infrastructure to come in to start drilling.
Great. And then, Taylor, you talked about $500,000 savings if you can go to 100% white sand versus ceramics. But can you talk about the level of impact that the legacy contracts you're still drilling the wells under could have on the well costs? So if the if you use sand, the 7.4% can theoretically go to 6.9% or 7% and if you go to market rates on rigs, what's the potential cost impact on that side?
So we're still working on what the contracts are going to be. But if you look in the market relative to our contracts, which were really in kind of mid-20s. We think you're going to see it's clearly going to be in the teens and it could be mid teens, but we still got to work through that. In terms of just pure drilling cost, our drilling cost in 3Q was about just a little over $2,500,000 and we think that could drop by another $300,000 kind of range to $400,000 as you those things roll off.
So combined, you're talking about a potential another $750,000 $800,000 potential savings if the white
Well, no, just it'd be $300,000 to $400,000 in total on drilling and some of that's contracts and some of it's efficiency, if that's what
you mean. Higher number would include if you could go
to the same as well.
Yes. No, absolutely, you're right, sorry, when you combine those 2.
Great. And then lastly, just a follow-up on Brad's OMS question, Michael, the $20,000,000 run rate of 3rd quarter EBITDA, is that a pretty good run rate or is really that $60,000,000 to $75,000,000 you talked about in prior calls, the right range for the current OMS system once you kind of average out the freshwater sales component?
Yes. I think that asset as it gets kind of fully ramped up can be still that 60 to 75 kind of longer term. I think that's probably a good number.
Perfect. Everything else has been asked. Thank you, guys.
All right, Ron. Thanks.
And our next question comes from David Deckelbaum from KeyBanc. Please go ahead, sir.
Good morning, Tommy, Michael and Taylor. Thanks for taking my questions.
You bet.
On the Wild Basin, Taylor, can you give us a little bit more color just on what that development is going to look like in terms of you have the 3 rigs out there. I understand the timing of drilling now and when production comes online. But can you talk about the pad design, the targets that you guys will be going after? And I assume that would these all be the similar high volume intensity completion that we're seeing right now in the core?
Yes. So the plan is to drill those primarily at this point in the Bakken in the first bench. We are still going to do some second bench test. In fact, our 1st spacing unit will have 2 2nd bench wells, but really the balance we think is going to be we'll be able to recover the reserves in the Bakken and the 1st bench. The configuration of the wells, density of spacing, we are still working on, but it's somewhere around probably 13 to 15 wells per spacing unit.
Could be lower if you continue to get really, really big wells, but early to make that determination. The configuration in terms of stimulation, at this point, we're planning to do all high intensity stimulation in both the Bakken and in the Three Forks. And then surface configuration is going to be like we've been doing. We typically have for each spacing unit 3 pads that we drill off of and we'll have at least 1 central processing facility for the fluids.
Okay, that's helpful. And are there should we be expecting sort of more tweaks to the high intensity completion design in terms of more sand loading or is sort of £9,000,000 the upper limit or are we going to see more than £4,000,000 tested on slickwater jobs?
We'll continue to optimize those fracs. What we've always done in the past and we've done over this last year is to apply a consistent completion method without changing a lot of things. And once we get a firm understanding of what the impact is of that completion, we'll start to change a few things. And so we will continue to optimize those on both types of completions in 2016 2017.
Just one last one if I might. Just Michael or Tommy whoever wants to take this one. But beyond the Wild Basin OMS build out, do you envision any other material upside in the out years for the OMS entity outside of just the organic growth just from production coming online? Or do you see like additional opportunity for facilities build outs in other areas?
Yes. David, that's a good question. If you'll remember the acquisition that we did back in late 2013, that asset actually came with kind of 3 of our areas including Painted Woods and Foreman Butte. In those areas, you have a little bit less infrastructure that we have the ability to potentially use OMS if that makes sense in those areas. Right now, we're evaluating that, but those are certainly opportunities.
There's also in the future opportunities potentially on the 3rd party side, but that's not something that we've done currently.
Got it. Thanks for your time and great job executing this quarter.
Thanks.
And the next question comes from Eric Otto CLSA. Please go ahead, sir.
Good morning. Thank you. So just a question, trying to get a little bit more color in terms of your thought process at higher oil prices. So can you give us some color on how you would think about outspend versus growth at say 55% and also how does paying down debt and hedging come into play at those levels?
Yes, I think it's a little bit of both. I think right now as we've talked about a lot of focus on the balance sheet and so in the near term, it's probably more to do with that in reducing our debt. And it will be a constant test of what is WTI doing, what is cost structure doing and how much cash we can generate. And like we said, is kind of keep volumes flattish. In an ideal world, if we can generate enough free cash to pay down debt and then maybe start expanding a bit, then great.
But in the near term, it's kind of focused on the balance sheet, which where the hedges come into play.
Is there a level of oil price in a period of time where we'd have to stick around that for you to get comfortable switching from cash flow neutrality to ramping up growth and out spending?
It's probably depending on cost structure again and ultimately it's about the margins. But it's probably somewhere in the $60 to $70 range, probably closer to $60 but we just got to we'll just play it by year.
Okay. Thank you.
You bet.
And the next question comes from Michael Rowe from TPH. Please go ahead, sir.
Yes. Good morning. Just wanted to make sure I'm understanding the 2016, dollars 350,000,000 drilling and completion spend that was cited earlier. So is that kind of assuming a $7,400,000 well cost and maybe 80% of the intense completions and then a lower well cost on the base completions?
Yes. It's the 7.4 cost. So you bake that in with about 70 completions and then running the 3 rigs. And with 3 rigs, we've talked about this in the past that it's about 16 wells a rig, so that's drilling about 50 wells. And so we'll work off our wells waiting on completion will actually drop a bit from what we're projecting at year end down to about 60 by or low 60s by the end of 2016.
Okay, very good. So that makes sense. I guess maybe shifting gears just a little bit. I know on the midstream monetization, there's not a whole lot you can mention. But is there a timing where you all think this really needs to get done?
Or I mean, how I guess how will the infrastructure spending trajectory look like throughout the year? And if it kind of the timing shifts a quarter or 2, is that a big deal in your view?
Yes. There's no specific time line, Michael, around when you have to get something done. The good thing for us is that we did start we started talking about this earlier this year, but with there were certainly a lot of changes that's happened in that business throughout the year that's improved our position, including outperformance on our current assets and getting closer to that Wild Basin asset and that coming online. And so all that's put us in a better position. We've got a significant amount of interest in it, but we don't have any specific timing on it.
Okay, great. And just maybe last one if I could. Recognizing it's a pretty minor portion of your cash flow stream, but just in terms of gas prices, do you expect to kind of all else equal that realizations will kind of remain at these levels heading into 2016?
Yes. Obviously our gas realizations as most have come down from a couple of years ago to where we are today. A lot of that's due to the lower NGL pricing. So right now, we do expect kind of gas pricing based on where the gas price is and where the oil price we expect it to be next year to be in that similar range. But that's moving around quite a bit.
Okay. Thanks very much.
And the next question comes from Noel Parks from Ladenburg Thalmann. Please go ahead, sir.
Good morning.
Good morning, Noel.
I had a few questions. I got on a bit late, so sorry if you've addressed any of these before. But as we look to reserves at year end, I just wondered if you just had any insight on sort of the moving parts. I mean, we know about, of course, the price component, But just wondering about how much of sort of that you might be able to get back just through lower costs? And also now I guess you've got more production history on a lot of the high intensity completions.
So just wondering about maybe also getting some help from revised curves?
So it's still early in that process. We're working on our reserves for year end. And you mentioned a lot of things that are going to have an impact and price is a huge one. And so our SEC price deck at the end of last year was around $95 a barrel. And based on pricing that we've seen so far this year, you're going to be in the low 50s.
And so that move from 95% to the low 50s is clearly going to have an impact. And when you think of where the impact is, the biggest piece is going to be on our undeveloped reserves and it's really for two reasons. We have some of those reserves that are booked outside the core area. And so those are going to be a little probably a little below the threshold of the economic cutoff. The other portion of that is with slow drilling activity and the SEC rule around capturing undeveloped reserves within a 5 year window, you're going to lose the ability to get some of those PUDs drilled in that timeframe.
So early to tell where the numbers going to fall out, but clearly it's downward bias with that lower price deck and we'll have more data after the end of the year.
Sure. And on the cost side, just I mean, is that a little bit of a help in offsetting some of the oil price sort of downdraft or doesn't really move the needle that much or?
No, it definitely helps. When you take into account, currently. And then also add on that reduction in LOE currently. And then also add on that reduction in LOE, significant reduction in the differentials. All those items have made a big impact.
And I think a good way to think about it, at least at this point, is when you look at our borrowing base redetermination, even with a pretty significant drop in the bank decks, we only our absolute commitment only dropped from $1,700,000,000 to $1,525,000,000
Right, right. Okay, thanks. That's helpful. And I started thinking a bit about when we see a rebound in prices to whatever degree, just kind of what the industry response to that would look like. And I was just wondering, do you agree that we've seen a lot of rigs laid down in the Bakken?
Are you aware, has most of that iron just been stacked locally? Or has it moved out of the basin as far as you can tell?
Yes. From what we know, most of that is most, if not all, has remained local in the basin. It is this downturn is a little different in that the companies have really worked hard to get those rigs into more centralized locations and leaving them out where they might get cannibalized and trying to have them in good shape for a rebound.
Great.
And I think that's I guess the only thing I was wondering is, I know your working interest is high across your properties, but have you been able to pick up any increases from seeing any of the non operators go non consent?
So we have this year and we also in past years have we've always had really a little bit of a bias up on our working interest as we go through the year. And so we've ended up having an average working interest this year that's kind of 75% to 80% range. And when we budgeted coming in, it was a bit lower than that. So we have benefited from the ability to pick those up, because it's all in these core wells that are really highly economic. The other thing that we've been able to do in the core is get some trades done.
And so we've been able to trade our non op interest in other guys' wells into working interest in our wells in the core. And so that's been a big help as well.
Can you give any sort of rough quantifying of that kind of what you've seen there?
No, that's really more trading acreage, right? So you're trading core acreage for core acreage with other operators, but it does get us we believe that our guys are doing a great job on the operating side getting costs down in a pretty differential way. So we want a higher impact to our own wells. And what you'll see is that very little of our capital goes to non op activity and that's because we continue to trade in and out of other people's wells back into our own.
Great. That's all for me.
And the next question comes from James Spicer from Wells Fargo. Please go ahead.
Yes. Hi, guys. Good morning. Most of my questions have been answered. Just a couple of clarifications on OMS, if I could.
First of all, on the Wild Basin gas plant, what was the total cost of building that plant? And then when you're thinking about monetization options, I assume that the gas plant is part of that. Is that correct?
Yes. In the Wild Basin, we've never given a direct number just for the gas plant James. But overall capital spend in Wild Basin is going to be on the order of magnitude of around $250,000,000 We said that over the next 2 years you're going to have an additional $150,000,000 So we've spent about $100,000,000 today, maybe a little bit over that. And then it will be included though in any package that we do, the plant as well as the infrastructure within Wild Basin.
Okay. And then just thinking about EBITDA generation potential for the asset as a whole, I think you said $60,000,000 to $75,000,000 for the existing asset and then another $60,000,000 just for the plant when it's up and running, so $120,000,000 to $135,000,000 on a pro form a basis?
That's correct.
Okay. That's it. Thank you.
Thanks, Jim.
Our next question comes from Gail Nicholson from the KLR Group. Please go ahead.
Good morning, everyone. Just looking at those 87 gross wells in backlog, is the average working interest in those wells in that 75% to 80% range? Or is it lower than that?
It is still in that kind of 70% range. It's not wildly different.
Okay. And then should we assume kind of in that 70% to 80% range in 2016 for the wells that are completed from a working interest standpoint?
Yes. The average interest is 70 ish maybe biased a little bit lower, but it's right around 70.
Okay, great. And then looking at the Wild Basin acreage, do you pick up a higher gas composition in Wild Basin versus Indian Hills?
Wild Basin does have a higher GOR than Indian Hills, deeper part of the basin and more gas content and more energy, but also higher EURs as well.
Okay, great. And then just looking at the differential, when you look at 2016, you talked about $5 less 9 the additional potential takeaway capacity coming online in 2016, do you feel like there could be more room for improvement in that differential? Then in a potential improving commodity price environment, do you feel like the 8% to 10% versus NYMEX, the historical norm is still fair? Or do you feel like it might have shifted down?
Yes. Good questions, Gail. I think the differential certainly has always kind of been in this 8% to 10% range in higher oil prices, lower oil prices and really for the long haul. There are periods of time where it gaps out either high or low. But for the most part, it tends to come back into this 8% to 10% range.
So I think we feel pretty comfortable that even if next year in a lower oil price environment, you're going to still be in that kind of 10% range. And then if oil prices come back dramatically, you'll probably have periods of time where it may be a little bit lower net, but it will probably rebalance out into that 8% to 10% range.
Okay, great. Thank you.
Thanks.
This concludes our question and answer session. I would now like to turn the conference back over to Tommy News for any closing remarks. Please go ahead, sir.
Great. Thanks. Oasis continues to be extremely focused on growing value. The frontline of offense has been our operations where you've seen and will continue to see substantial moves in capital efficiency with well cost down by 30%, LOE down by 25% and well productivity from high intensity completions up over 30% in the core. When coupled with our liquidity of over 1,300,000,000 dollars we are in a strong position and have considerable financial flexibility for the foreseeable future.
This is a great position to be in whether we see a prolonged down cycle or start to see a rebound in oil prices. Thanks for participating in our call today.
The conference has now concluded. Thank you for attending today's presentation. You may now disconnect the line.