Chord Energy Corporation
Q3 2015 Earnings Call Transcript

Published: 4 Nov 2015

[Operator:]

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 Third Quarter 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 Lou, Oasis Petroleum's CFO, to begin the conference. Thank you. Mr. Lou, you may begin your conference, sir.

[Michael H. Lou:]

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 Tommy 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.

[Thomas B. Nusz:]

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 the 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 are 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. 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 – we were 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, 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 2016, in fact greater than 80% high intensity. On the drilling side, we intended to run five 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 the three 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 are making on our 80 million 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 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 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 first quarter of 2016, we expect similar production compared to the fourth quarter of 2015, but volume 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 quarter range from 25% to 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, 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.

[Taylor L. Reid:]

Thanks, Tommy. The Williston Basin continues to be the premier oil basin in North America, and 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, and our performance in 2015 is further evidence that we have both. Our team further reduced our well costs this quarter and, as a result, slickwater completions in the core now cost $7.4 million, which is less than 10% over our base well costs to compete 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 $3.9 million 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 third-party frac crews at the beginning of the year without penalties. And 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 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 core. And we recently completed three tests in Indian Hills. These wells are in early flow back, 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 $7.4 million well costs 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 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're 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've 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 the 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 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 a way 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 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 that set us up for the future. With that, I'll turn the call over to Michael.

[Michael H. Lou:]

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' produced water and another quarter of high fresh water 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're exploring avenues to monetize a portion of OMS and 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 Wild Basin infrastructure project, Tommy 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 Wild Basin assets, 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 $1.35 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've 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.

[Operator:]

Thank you, sir. We will now begin the question-and-answer session. First question comes from Neal Dingmann from SunTrust. Please go ahead, sir.

[Neal D. Dingmann:]

Good morning, guys. Say, just your thoughts, you mentioned about going to obviously the Wild Basin area, just, Tommy, your thoughts about looking at Alger and some of these other areas, if you would consider going into any of those areas in 2016?

[Thomas B. Nusz:]

Yes, 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, 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 2016. 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.

[Neal D. Dingmann:]

No, makes sense. And then, just one last one. Obviously, liquidity, and Michael mentioned about, not having obviously (17

[Thomas B. Nusz:]

You mean the OWS business, the frac services business or OMS?

[Neal D. Dingmann:]

I'm sorry, OWS.

[Thomas B. Nusz:]

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 don't think that we will receive the value in the external market for that that we receive by owning it ourselves and maintaining the efficiency and flexibility in that business and our ability to control cost all the way through the value, through the supply chain. So, I think it's much more valuable to us at this point than it is externally.

[Neal D. Dingmann:]

Yes. I got to agree to this point. Thanks, Tommy.

[Thomas B. Nusz:]

You bet.

[Operator:]

And the next question comes from Ryan Oatman from Cowen. Please go ahead, sir.

[Ryan Oatman:]

Hi, good morning.

[Thomas B. Nusz:]

Good morning.

[Ryan Oatman:]

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?

[Michael H. Lou:]

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, but 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. LOE's come in dramatically. Differentials have come in dramatically. So, all of 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.

[Thomas B. Nusz:]

Yes, keep in mind that at the end of last year, well costs for these high intensity completions were running somewhere around $10.5 million and that now is $7.4 million; so, a big move in initial cost, along with all the other components coming down as well.

[Ryan Oatman:]

No, that's helpful. And then you guys have mentioned that the slickwater well costs that use ceramic, the cost for those have come down. Is it the ceramic cost itself decreasing and then 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?

[Taylor L. Reid:]

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 improved the well costs from that standpoint. And then like I said, the other half in service and material side of the business.

[Ryan Oatman:]

That's very good. And then, one final one for me. I noticed in the back of the presentation, the illustrative high intensity EURs, looks like it was about 850 MBoe last quarter, looks like there is now two curves there, one at 875 MBoe, another at 975 MBoe. Just wanted to see kind of what drove that change and what your latest thoughts are for EURs? Thanks.

[Taylor L. Reid:]

Yes. It's just a reflection of what we're seeing in the quarter, the range of 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 just added back to reflect the performance that we've actually seen in the wells.

[Operator:]

And our next question comes from Tim Rezvan from Sterne Agee. Please go ahead, sir.

[Timothy A. Rezvan:]

Hi. Good morning, folks. I was hoping to just clarify, I guess, some of the comments you'd 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? And then, I guess on top of that there's this back ended skew to production growth. Is that kind of a fair assessment of what you've described?

[Michael H. Lou:]

Yes, 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. And 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 the 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. And maybe as opposed to the flattish production you've seen this year, it may be a little bit more skewed next year.

[Timothy A. Rezvan:]

Okay. Okay. And then, I guess if we – 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 million kind of gross spend for 2016?

[Michael H. Lou:]

Yes. If we did nothing next year on that OMS asset, that would mean at a $50 deck, $150 million of outspend. Obviously, we have the ability to do that under our liquidity, but that's not our preferred route.

[Timothy A. Rezvan:]

Okay. Okay; just wanted to clarify that. Thank you.

[Michael H. Lou:]

Thanks, Tim.

[Operator:]

And our next question comes from Vedran Vuk from Wunderlich. Please go ahead.

[Vedran Vuk:]

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 fourth 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 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?

[Taylor L. Reid:]

So, first on the production guidance going into the fourth quarter, there's two things. One, we do have a few less wells that we're going to complete in the fourth quarter, relative to third quarter, but we're also factoring in normal winter conditions that we see, 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, it could drive the other way as well. With respect to the high intensity completions, what we model is 30% uplift, on average, and clearly we're seeing better performance than 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 quarter, which is Indian Hills, and especially Wild Basin next year.

[Thomas B. Nusz:]

Yes, one of the things we've 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 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.

[Vedran Vuk:]

Okay. Thanks, guys.

[Operator:]

And our next question comes from Brad Carpenter from Cantor Fitzgerald. Please, go ahead.

[Brad Carpenter:]

Hey, morning, guys, and congrats on the nice quarter.

[Thomas B. Nusz:]

Thanks.

[Brad Carpenter:]

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?

[Michael H. Lou:]

I'm sorry, Brad, fourth quarter, what was lower?

[Brad Carpenter:]

Sorry, the – so the OMS guidance of over $60 million on EBITDA for the full year, just looking at the first nine months, I'm getting to a lower sequential 4Q number. So, I was hoping you could just talk about the moving parts behind that?

[Michael H. Lou:]

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 and so that drove some of the outperformance. The other part of it was there was a high amount of fresh water sales, but OMS doesn't supply 100% of the fresh water in all areas to the company, in some areas we go with third-parties. And so in those areas, you're not going to make as much money for OMS, so that fresh water sales may not be as high going forward.

[Brad Carpenter:]

Got you. Okay, that's helpful. Thanks. And then 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?

[Michael H. Lou:]

Yes, if everything goes according to plan and you get to call it the end of 2017, all of that infrastructure should be running fairly full capacity by then. That asset could produce over $60 million of EBITDA on its own.

[Brad Carpenter:]

Okay, great. All right, that's very helpful. All right, thanks, guys.

[Michael H. Lou:]

Thanks.

[Operator:]

And the next question comes from Ron Mills from Johnson Rice & Company. Please go ahead.

[Ronald E. Mills:]

Good morning. Couple of questions; just on the DUC breakdowns, 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 Alger areas i.e. the core or are some still spread across some of your other areas?

[Taylor L. Reid:]

So you're right. We got 87 into this quarter and we think we'll be at low 80 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.

[Ronald E. Mills:]

And are those DUCs or are those outside the core, those are in areas nearby existing gathering systems in such a way those would be relatively easy to bring on?

[Taylor L. Reid:]

Yes, it's a great point. There is quite a few of them that are, in fact the majority are in Eastern Red Bank and we've got whole infrastructure in and around that area and that's really one of our better performing areas, in fact we got that highlighted in the presentation this quarter on page 12.

[Michael H. Lou:]

And, 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 of the core, 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 growing.

[Ronald E. Mills:]

Great. And then, Taylor, you talked about $0.5 million savings, if you can go to 100% white sand versus ceramics, but can you talk about the level of impact that these legacy contracts you're still drilling the wells under could have on the well costs? So if you use sand, the $7.4 million can theoretically go to $6.9 million or $7 million, and if you go to market rates on rigs, what's the potential cost impact on that side?

[Taylor L. Reid:]

So, we're still working on what the contracts are going to be, but if you look in the market, relative to you, our contracts, which were really in kind of mid-20%-s, 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 costs, our drilling costs in 3Q was about, was just a little over $2.5 million, and we think that could drop by another $300,000 kind of range to $400,000 as those things roll off.

[Ronald E. Mills:]

So, combined you're talking about a potential another $750,000, $800,000 potential savings, if the white sand works well?

[Taylor L. Reid:]

Well, no, it'd be $300,000 to $400,000 in total on drilling, and some of that's contracts, and some of it is efficiency, if that...

[Ronald E. Mills:]

The higher number would include if you (33

[Taylor L. Reid:]

Yes, no, absolutely right, sorry; when you combine those two.

[Ronald E. Mills:]

Great. And then 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 to $75 million you talked about in prior calls, the right range for the current OMS system once you kind of average out the fresh water sales component?

[Michael H. Lou:]

Yes. I think that asset as it gets kind of fully ramped up can be still about $60 million to $75 million kind of longer-term, I think that's probably a good number.

[Ronald E. Mills:]

Perfect. Everything else has been asked. Thank you, guys.

[Thomas B. Nusz:]

All right, Ron. Thanks.

[Operator:]

And our next question comes from David Deckelbaum from KeyBanc. Please go ahead, sir.

[David A. Deckelbaum:]

Morning, Tommy, Michael and Taylor. Thanks for taking my questions.

[Thomas B. Nusz:]

You bet.

[David A. Deckelbaum:]

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 three rigs out there. I understand the timing of starting the drilling now and one 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 quarter?

[Taylor L. Reid:]

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 tests, in fact our first spacing unit will have two second bench wells, but 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 wells per spacing unit to 15 wells per spacing unit. It could be lower if you continue to get really, really big wells, bit 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 three spacing units, three pads that we drill off of and we'll have at least one central processing facility for the fluids.

[David A. Deckelbaum:]

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 million pounds the upper limit or are we going to see more than 4 million pounds tested on slickwater jobs?

[Taylor L. Reid:]

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'll continue to optimize those and on both types of completions in 2016 and 2017?

[David A. Deckelbaum:]

And then just one last one if I may, it's just, Michael or Tommy are the ones to take this one, but beyond the Wild Basin, OMS build-out, could 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?

[Michael H. Lou:]

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 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, but those are certainly opportunities. There's also, in the future opportunities, potentially on the third-party side, but that's not something that we've done currently.

[David A. Deckelbaum:]

Got it. Thanks for your time and great job executing this quarter.

[Thomas B. Nusz:]

Thanks.

[Operator:]

And the next question comes from Eric Otto from CLSA. Please go ahead, sir.

[Eric Otto:]

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?

[Thomas B. Nusz:]

Yes, I think it's a little bit of both. I think right now, as we've talked about, lot of focus on the balance sheet. And so, in the near-term it's probably more to do with that and reducing our debt. And it'll be a constant test of what is WTI doing, what is cost structure doing and how much cash we can generate? And like we've said, it's 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, and then great. But in the near-term, it's kind of focus on the balance sheet, which where the hedges come into play.

[Eric Otto:]

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 in outspending?

[Thomas B. Nusz:]

It's probably depending on the 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'll just play it by year.

[Eric Otto:]

Okay. Thank you.

[Thomas B. Nusz:]

You bet.

[Operator:]

And the next question comes from Michael Rowe from TPH. Please, go ahead, sir.

[Michael J. Rowe:]

Yes, good morning. Just wanted to make sure I'm understanding the 2016 $350 million drilling and completion spend that was cited earlier. So, is that kind of assuming a $7.4 million well cost and on maybe 80% (41

[Taylor L. Reid:]

Yes. It's the $7.4 million cost, so you bake that in with about 70 completions. And then, running the three rigs – and with three 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.

[Michael J. Rowe:]

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 that 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 two quarters, is that a big deal in your view?

[Michael H. Lou:]

Yes, there is 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, 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 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.

[Michael J. Rowe:]

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?

[Michael H. Lou:]

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.

[Michael J. Rowe:]

Okay. Thanks very much.

[Operator:]

And the next question comes from Noel Parks from Ladenburg Thalmann. Please go ahead, sir.

[Noel A. Parks:]

Good morning.

[Thomas B. Nusz:]

Good morning, Noel.

[Noel A. Parks:]

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 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?

[Taylor L. Reid:]

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 cut off. 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. So, early to tell where the number's 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.

[Noel A. Parks:]

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...?

[Taylor L. Reid:]

No, it definitely helps. When you take into account, like we said, this reduction of well costs 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. And I think, a good way to think about at least at this point is, when you look at our borrowing base redetermination, even with pretty significant drop in the bank decks, our absolute commitment only dropped from $1.7 billion to $1.525 billion in deck.

[Noel A. Parks:]

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's the industry response to that would look like. And, I was just wondering, 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?

[Taylor L. Reid:]

Yes. From what we know, most of that is – most, if not all, has remained local in the basin. This downturn is a little different and that the companies have really worked hard to get those rigs in to kind of more centralized locations and leaving them out where they might get cannibalized and trying to have them in good shape for rebound.

[Noel A. Parks:]

Great. And, I guess the only thing I was wondering is that 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 going non-consent?

[Taylor L. Reid:]

So, we have this year and 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. And so, we've ended up, having an average working interest this year that kind of 75% to 80% range, and when we budgeted coming in, that 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 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 quarter so that's been a big help as well.

[Noel A. Parks:]

Can you give any sort of rough quantifying of that kind of what you've seen there?

[Michael H. Lou:]

No, that's really more trading acreage rate. 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 cost down in a pretty differential way. So, we want a higher impact to our own wells. And what you will 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 – out of other people's wells back into our own.

[Noel A. Parks:]

Great. That's all for me.

[Operator:]

And the next question comes from James Spicer from Wells Fargo. Please go ahead.

[James A. Spicer:]

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 gas plant is part of that, is that correct?

[Michael H. Lou:]

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 million. We said that over the next two years, we're going to have an additional $150 million. So, we've spent about $100 million to date, 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.

[James A. Spicer:]

Okay. And then, just thinking about EBITDA generation potential for the asset as a whole; I think, you said $60 million to $75 million for the existing asset and then another $60 million just for the plant when it's up and running, so $120 million to $135 million on a pro forma basis?

[Michael H. Lou:]

That's correct.

[James A. Spicer:]

Okay, that's it. Thank you.

[Michael H. Lou:]

Thanks, Jim.

[Operator:]

And our next question comes from Gail Nicholson from the KLR Group. Please, go ahead.

[Gail Nicholson:]

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?

[Taylor L. Reid:]

It is still in that kind of 70% range, it's not widely different.

[Gail Nicholson:]

Okay. And then, if we assume kind of in that 70% to 80% range in 2016 for the wells that are completed from a working interest standpoint?

[Taylor L. Reid:]

Yes, the average interest is 70%-ish, maybe biased a little bit lower, but it's right around 70%.

[Gail Nicholson:]

Okay, great. And then, looking at the Wild Basin acreage, do you pick up a higher gas composition in Wild Basin versus Indian Hills?

[Taylor L. Reid:]

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.

[Gail Nicholson:]

Okay, great. And then just looking at the differential when you look at 2016 you talked about $5 less NYMEX. With the additional potential takeaway capacity that's coming on line in 2016, do you feel like, there could be more room for improvement in that differential? And 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?

[Michael H. Lou:]

Yes. Good questions, Gail. I think the differential certainly has always kind of been in the 8% to 10% range. In higher oil prices, lower oil prices and really for the long haul, there are periods of time, where it gassed 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 maybe a little bit lower than that, but it'll probably rebalance out into that 8% to 10% range.

[Gail Nicholson:]

Okay, great. Thank you.

[Michael H. Lou:]

Thanks.

[Operator:]

So, this concludes our question-and-answer session. I would now like to turn the conference back over to Tommy Nusz for any closing remarks. Please, go ahead, sir.

[Thomas B. Nusz:]

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 costs 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.

[Operator:]

The conference has now concluded. Thank you for attending today's presentation. You may now disconnect the line.