Good morning. My name is Frank. I will be your conference operator today. At this time, I'd like to welcome everybody to the third quarter 2015 earnings release operations update for Oasis Petroleum. All participants will be in listen-only mode. Should you need assistance, please signal a conference specialist by pressing the star key followed by zero. After today's presentation, there'll be an opportunity to ask questions. To ask a question, you may press star then one on your touchtone phone. To withdraw your question, please press star then two. Please note this event is being recorded. I would now like to turn the call over to Michael Lou, Oasis Petroleum CFO, to begin the conference. Thank you. Mr. Lou, you may begin your conference, sir.
Thank you, Frank. Good morning, everyone. This is Michael Lou. Today, we are reporting our third quarter 2015 financial and operational results. We're delighted to have you on our call. I'm joined today by Thomas Nusz 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-K and our quarterly reports on Form 10-Q.
We disclaim any obligation to update these forward-looking statements. During this conference call, 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 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. 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 2015 and has set us up for a successful 2016, even if we don't see a more bullish commodity backdrop. We're proud to report that we have exceeded expectations on all fronts this quarter. We delivered a beat on production, differentials, LOE, G&A, EBITDA, well costs, and cash flow, and that is with WTI averaging $46.43 for the quarter.
Earlier this year, we felt like that we were positioned to be free cash flow positive in 2016 with WTI at $60 per barrel. 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 and 2016 continues to be basically the same as our original plans, 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 2016, in fact, greater than 80% high intensity.
On the drilling side, we intended to run five rigs throughout 2015 to complete our program. Our drilling team has knocked down the drilling days such that we were able to ramp down to three rigs mid-year 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 million a day gas processing plant. 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 fourth quarter plan has us completing a few less net wells compared to the 15.4 net operated wells we completed in the third quarter. We're hedging against some winter weather impacts. We've essentially maintained our flattish production volume guidance. Given continued winter operations in the first quarter of 2016, we expect similar production compared to the fourth quarter 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.
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%-40% at $50 WTI. In light of those economics and the downside protection afforded by our hedge program, we continued to layer in swaps during the third quarter of 2015, providing protection in 2016 for about half of our production. 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 America. Oasis continues to be a leading operator in the 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. Our performance in 2015 is further evidence that we have both. Our team further reduced our well cost this quarter. As a result, slickwater completions in the core now cost $7.4 million, 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. 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 $3.9 million in 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 third-party frac crews at the beginning of the year without penalties. Since that time, OWS has handled 100% 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 first quarter, 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 third quarter. 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 core. We recently completed three tests in Indian Hills.
These wells are in early flow-back. If their results are the same as we have seen in Montana, where production with and without ceramic are very similar, 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 $7.4 million well cost that I spoke to earlier. 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 third-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 million in drilling and completion capital next year, which should result in flat to slightly growing production for the year. Additionally, it is especially encouraging to note that these cost reductions and performance enhancements extend to our acres 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 second quarter. This improvement was driven by two things. First, an increase in produced water volumes being transported on OMS pipelines. We exited the third quarter with 75% of our produced water 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 runtimes on our wells. LOE per BOE may increase slightly as we head into the winter months. 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 2015. 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, 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 million. Our midstream business delivered $20.5 million of adjusted EBITDA, primarily due to gathering a higher percentage of Oasis's produced water and another quarter of high freshwater sales. We now anticipate that OMS will generate over $60 million of adjusted EBITDA in 2015, which significantly exceeds our original projections of approximately $40 million 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, we seek to bring in external capital to fund our 2016 infrastructure program of approximately $150 million.
Most of this capital will be focused on the Williston Basin infrastructure project Tommy Nusz described earlier. We have significant interest in the midstream assets and given the outperformance of the business this year, coupled with the progress in the Williston Basin assets, we believe we are in a significantly stronger position to maximize the value of this rapidly growing business while maintaining control. We exited the quarter with liquidity of $1.35 billion, and in the first 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 billion. CapEx came in lighter than expected during the third quarter. As well costs came down rapidly throughout the year, actuals came in below engineering estimates, and the true-up of about $50 million led to our lower CapEx during the third quarter.
Importantly, this does not change our year-to-date capital expenditures of $520 million, and we will still see full year 2015 CapEx come in at or under our current $670 million capital plan. With CapEx down 57% 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 first quarter of 2015 to below $5 in the third quarter. We are now expecting our differential to remain between $4 and $5 for the fourth quarter 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&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 third quarter of 2015. With all of the hard work 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 will 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. To ask a question, you may press star, then one on your touch-tone phone. If you are using a speakerphone, please pick up your handset before pressing the keys. To withdraw your question, please press star, then two. At this time, we will pause momentarily to assemble our roster. First question comes from Neal Dingmann from SunTrust. Please go ahead, sir.
Morning, guys. Just your thoughts, you mentioned about going to obviously the Wild Basin area. Just Tommy Nusz, your thoughts about looking at Eldridge and some of these other areas, if you would consider going to any of those areas in 2016.
Yeah. Neal, we're right now transitioning to where all three rigs will be in Wild Basin in preparation for the startup of the plant in the second half of the year. Latter part of the year, we may have a few in some of the other areas from a drilling standpoint. 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 2016. 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. Just one last one. Obviously, liquidity and Michael mentioned about not having obviously much of an outspend issue, if any. There's no issues there, your thoughts about if you would look into monetizing the midstream services anytime soon.
You mean the OWS business, the frac services business or OMS?
I'm sorry, the OWS.
Yeah. 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 don't think that we would receive the value in the external market for that we receive by owning it ourselves and maintaining the efficiency and flexibility in that business and our ability to control costs all the way through the supply chain. I think it's much more valuable to us at this point than it is externally.
Yeah. I think I'd agree at this point. Thanks, Tommy.
You bet.
The next question comes from Ryan Oatman from Cowen. Please go ahead, sir.
Hi, good morning.
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% 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 were 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 into a little bit more detail. The IRRs continue to improve from a number of standpoints. One, 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. All the different pieces have contributed to it. I don't have exactly the breakout of what contributed what there. Overall, everything's contributing to those IRRs improving, even at lower pricing.
Yeah, keep in mind that at the end of last year, well costs for these high-intensity completions were running somewhere around $10.5 million. That now is $7.4 million. A big move in initial cost, along with all the other components coming down as well.
That's helpful. You guys had mentioned that the slickwater well cost, that they use ceramic, the cost for those have come down. Is it the ceramic cost itself that's decreasing? If that's the case, how would that change the math in terms of potential savings from shifting from, say, 4 million pounds of ceramic to 9 million pounds of sand?
It's pretty even. It's across the well. It's not just materials. There's a combination of things that have driven the cost down. As we're showing, of all the cost savings so far, about half of that have been service reductions. The other half has really been around efficiency. We've gotten much more efficient in terms of cycle times, eliminated downtime, and really improved the well cost from that standpoint. Like I said, the other half being service and material side of the business.
That's very good. One final one for me. I noticed in the back of the presentation, the illustrative high-intensity EURs looked like it was about 850 BOE last quarter. Looks like there's now two curves there, one at 875, another at 975. Just wanted to see what drove that change and what your latest thoughts are for EURs. Thanks.
Yeah, it's just a reflection of what we're seeing in the core of the range of performance. 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. We just added that to reflect the performance that we've actually seen in the wells.
Our next question comes from Tim Rezvan from Sterne Agee. Please go ahead, sir.
Hi, good morning, folks. I was hoping to just clarify, I guess, some of the comments you 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 million spending to keep production flattish and be roughly free cash flow neutral? Is that kind of what you're thinking? Then I guess on top of that, this back-ended skew to production growth. Is that kind of a fair assessment of what you've described?
Yeah, Tim, that's pretty much what we're talking about. $350 million of D&C capital we'd spend within cash flow at a $50 oil price. That would keep production flat to growing slightly. Then what Tommy mentioned was that because of weather, we've given guidance on the fourth quarter that volumes may come down just a touch, and you might see that at the beginning of next year, 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. I guess you talked about the OMS monetization. It sounds like you are moving down that path. If you don't get something done, does that imply a $150 million kind of gross spend for 2016?
Yeah, if we did nothing next year on that OMS asset, that would mean at a $50 DUC, $150 million of outspend. Obviously, we have the ability to do that under our liquidity, that's not our preferred route.
Okay. Just wanted to clarify that. Thank you.
Thank you.
Our next question comes from [Jason Wangler] from Wunderlich. Please go ahead.
Hi, guys. Just had a few questions on the production guidance. I was wondering how much of the winter effects are baked into the fourth quarter numbers. I'm wondering if the winter's a little milder than expected, should we assume that you guys will be above that range? 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 those 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?
First, on the production guidance going into the fourth quarter, there are two things. One, we do have a few less wells that we're going to complete in the fourth quarter relative to third quarter, we're also factoring in normal winter conditions that we see, especially get that usually December timeframe, and it can be wildly variable. If you have a really warm winter, we could do a little better, really cold, it could drive the other way as well. With respect to the high-intensity completions, what we model is 30% uplift on average. Clearly, we're seeing better performance than that in some of the areas. 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.
All right. Great.
One of the things we've figured out is we're not very good at predicting the weather. 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. As always, we kind of hedge a little bit against weather because we just don't know.
Okay. Thanks, guys.
Our next question comes from Brad Carpenter from Cantor Fitzgerald. Please go ahead.
Hey, morning, guys, congrats on the nice quarter.
Thanks.
I had a few questions on OMS. I was looking at your guidance of over $60 million EBITDA for the full year, and that, to me, suggests a sequential decline in 4Q. I'm just curious, what are the drivers behind that implied lower 4Q number versus 3Q?
I'm sorry, Brad. Fourth quarter, what was lower?
Sorry. The OMS guidance of over $60 million EBITDA for the full year. Just looking at the first nine months.
Got it.
I'm getting to a lower sequential 4Q number. I was hoping you could just talk about the moving parts behind that.
Sure. One of the things that I mentioned was that the third quarter, and really the second quarter, was a couple of things. One, we were getting more of our wells connected to the system on the produced water side, that drove some of the outperformance. The other part of it was there was a high amount of freshwater sales, OMS doesn't supply 100% of the freshwater in all areas to the company. In some areas, we go with third parties. In those areas, you're not going to make as much money for OMS. That freshwater sales may not be as high going forward.
Got you. Okay, that's helpful. Thanks. Looking at the Wild Basin project, you guys have laid out that $150 million of CapEx for 2016 and 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.
Yeah. If everything goes according to plan 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 million of EBITDA on its own.
Okay, great. All right, that's very helpful. All right, thanks, guys.
Thanks.
The next question comes from Ron Mills from Johnson Rice & Company. Please go ahead.
Good morning. A couple 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 are some still spread across some of your other areas?
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. 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. They're in close proximity. 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.
Are those outside the core? Those are in areas nearby existing gathering systems and such, where those would be relatively easy to bring on?
Yeah, 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.
Ron, that's a great point. In terms of the maturity of our asset, because we have drilled most of our asset, as we look at inventory outside the core, most of that inventory actually has very good infrastructure. It's not something that we would have to wait for additional infrastructure to come in to start drilling.
Great. Taylor, you talked about half a million dollars savings if you can go to 100% white sand versus ceramics. 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? If you use sand, the $7.4 can theoretically go to $6.9 or $7.0. If you go to market rates on rigs, what's the potential cost impact on that side?
We're still working on what the contracts are going to be. If you look in the market relative to our contracts, which were really in the 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 two and a half million, and we think that could drop by another $300,000-$400,000 as those things roll off.
Combined, you're talking about a potential another $750,000-$800,000 potential savings if the white sand works as well.
Well, no, it'd be $300,000-$400,000 in total on drilling. Some of that's contracts and some of it's efficiency. If that's what you mean?
No, the higher number would include if you could do the white sand as well.
Oh, yeah. No, you're right. Sorry. When you combine those two, yeah.
Lastly, just to follow up on Brad's OMS question, Michael, the $20 million run rate of third quarter EBITDA, is that a pretty good run rate, or is really that $60 million-$75 million you talked about in prior calls the right range for the current OMS system once you average out the freshwater sales component?
Yeah, I think that that asset, as it gets fully ramped up, can be still that $60 million-$75 million longer term. I think that's probably a good number.
Perfect. Everything else has been asked. Thank you, guys.
All right, Ron. Thanks.
Our next question comes from David Deckelbaum from KeyBank. Please go ahead, sir.
Morning, Tommy, Michael, and Taylor. Thanks for taking my questions.
You bet.
On the Williston 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'll have the three rigs out there. I understand the timing of starting the drilling now and when production comes online. Can you talk about the pad design, the targets that you guys will be going after? And I assume would these all be the similar high-intensity volume intensity completion that we're seeing right now in the core?
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 tests. In fact, our first spacing unit will have two second bench wells. Really the balance we think is going to be, we'll be able to recover the reserves in the Bakken in the first bench. The configuration of the wells, density of spacing, we are still working on, but it's somewhere around probably 13-15 wells per spacing unit. Could be lower if you continue to get really big wells that 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. Surface configuration is going to be like we've been doing.
We typically have for each spacing unit, three pads that we drill off of, we'll have at least one central processing facility for the fluids.
Okay, that's helpful. Should we be expecting more tweaks to the high-intensity completion design in terms of more sand loading? Or is 9 million pounds the upper limit? Are we going to see more than 4 million pounds 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. Once we get a firm understanding of what the impact is of that completion, we'll start to change a few things. So we'll continue to optimize those on both types of completions in 2016 and 2017.
Just one last one, if I might. It's just, Michael or Tommy, whoever wants to take this one. 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? Do you see additional opportunity for facilities build-outs in other areas?
Yeah. David, that's a good question. If you'll remember the acquisition that we did back in late 2013, that asset actually came with three 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. Those are certainly opportunities. There's also, in the future, opportunities potentially on the third-party side. That's not something that we've done currently.
Got it. Thanks for your time. Great job executing this quarter.
Thanks.
The next question comes from Eric Otto from CLSA. Please go ahead, sir.
Good morning. Thank you. Just a question, trying to get a little bit more color in terms of your thought process at higher oil prices. Can you give us some color on how you would think about outspend versus growth at, say, $55? Also, how does paying down debt and hedging come into play at those levels?
Yeah. 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. So, in the near term, it's probably more to do with that and reducing our debt. It'll be a constant test of what is WTI doing, what is cost structure doing, and how much cash we can generate. Like we said, just keep volumes flattish. In an ideal world, if we can generate enough free cash to pay down debt, maybe start expanding a bit, great. In the near term, it's focused on the balance sheet, which is where the hedges come into play.
Is there a level of oil price and 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 outspending?
It's probably depending on cost structure, again. Ultimately, it's about the margins. It's probably somewhere in the $60 to $70 range, probably closer to 60. We'll just play it by ear.
Okay. Thank you.
You bet.
The next question comes from Mike Sharkey from TPH. Please go ahead, sir.
Yes, good morning. Just wanted to make sure I'm understanding the 2016 $350 million drilling and completion spend that was cited earlier. Is that assuming a $7.4 million well cost and maybe 80% of the intense completions, and then a lower well cost on the base completions?
Yeah. It's the 7.4 cost. You bake that in with about 70 completions, and then running the three rigs. With three rigs, we've talked about this in the past, that it's about 16 wells a rig, that's drilling about 50 wells. 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 or low 60s by the end of 2016.
Okay. Very good. 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 how will the infrastructure spending trajectory look like throughout the year? And if the timing shifts a quarter or two, is that a big deal in your view?
Yeah. There's no specific timeline, Michael, around when you have to get something done. The good thing for us is that we started talking about this earlier this year. 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. All of 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. 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, all else equal, that realizations will remain at these levels heading into 2016?
Yeah. 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. Right now, we do expect gas pricing based on where the gas price is and where the oil price we expect it to be next year to be in a similar range. That's moving around quite a bit.
Okay. Thanks very much.
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. As we look to reserves at year-end, I just wondered if you just had any insight on sort of the moving parts. We know about, of course, the price component, but just wondering about how much 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. Just wondering about maybe also getting some help from revised curves.
It's still early in that process. We're working on our reserves for year-end. You mentioned a lot of things that are going to have an impact. Price is a huge one. Our SEC price deck at the end of last year was around $95 a barrel. Based on pricing that we've seen so far this year, you're going to be in the low 50s. That move from 95 to the low 50s is clearly going to have an impact. When you think of where the impact is, the biggest piece is going to be on our undeveloped reserves. It's really for two reasons. We have some of those reserves that are booked outside the core area. Those are going to be 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 five-year window, you're going to lose the ability to get some of those PUDs drilled in that timeframe. Early to tell where the numbers are going to fall out. Clearly, it's downward bias with that lower price deck. We'll have more data after the end of the year.
Sure. On the cost side, just 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, like we said, this reduction in well cost from what was $10.5 million at the end of last year to $7.4 million currently, and then also add on that reduction in LOE, significant reduction in the differentials, all those items have made a big impact. 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, our absolute commitment only dropped from $1.7 billion to $1.525 billion.
Right. Okay, thanks. That's helpful. I started thinking a bit about when we see a rebound in prices to whatever degree, just what the industry response to that would look like. 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?
Yeah. From what we know, most, if not all, has remained local in the basin. 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. I think that's it. I guess the only other thing I was wondering is I know your working interest is high across your properties, have you been able to pick up any increases from seeing any of the non-operators go non-consent?
We have this year, we also in past years, we've always had really a little bit of a bias up on our working interest as we go through the year. We've ended up having an average working interest this year that's 75%-80% range. When we budgeted coming in, it was a bit lower than that. 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. We've been able to trade our non-op interest in other guys' wells into working interest in our wells in the core. 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? You're trading core acreage for core acreage with other operators. We believe that our guys are doing a great job on the operating side, getting costs down in a pretty differential way. We want a higher impact to our own wells. 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.
The next question comes from James Spicer from Wells Fargo. Please go ahead.
Yeah. Hi, guys. Good morning. Most of my questions have been answered. Just a couple clarifications on OMS, if I could. First of all, on the Wild Basin gas plant, what was the total cost of building that plant? Then, when you're thinking about monetization options, I assume that the gas plant is part of that. Is that correct?
Yeah. In the Wild Basin, we've never given a direct number just for the gas plant, James. Overall, capital spend in Wild Basin is going to be on the order of magnitude of around $250 million. We said that over the next two years, you're going to have an additional $150 million. We've spent about $100 million to date, maybe a little bit over that. It will be included though in any package that we do, the plant as well as the infrastructure within Wild Basin.
Okay. Just thinking about the EBITDA generation potential for the asset as a whole. I think you said $60 million-$75 million for the existing asset, and then another $60 million just for the plant when it's up and running. $120 million-$135 million on a pro forma basis?
That's correct.
Okay. That's it. Thank you.
Thanks, James.
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%-80% range, or is it lower than that?
It is still in that kind of 70% range. It's not wildly different.
Should we assume in that 70%-80% range in 2016 for the wells that are completed from a working interest standpoint?
Yeah. The average interest is 70-ish, maybe biased a little bit lower, but it's right around 70.
Okay, great. 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, also higher EURs as well.
Okay, great. Just looking at the differential, when you look at 2016, you talked about $5 less NYMEX. With the additional potential takeaway capacities coming online in 2016, do you feel like there could be more room for improvement in that differential? In a potential improving commodity price environment, do you feel like the 8%-10% versus NYMEX, the historical norm, is still fair, do you feel like it might have shifted down?
Yeah. Good questions, Gail. I think the differential certainly has always been in this 8%-10% range in higher oil prices, lower oil prices, really for the long haul. There are periods of time where it gaps out either high or low. For the most part, it tends to come back into this 8%-10% range. 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 10% range. If oil prices come back dramatically, you'll probably have periods of time where it may be a little bit lower than that, it'll probably rebalance out into that 8%-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 Thomas Nusz for any closing remarks. Please go ahead, sir.
Great. Thanks. Oasis continues to be extremely focused on growing value. The front line 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 $1.3 billion, 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.