Chord Energy Corp (CHRD) 2016 Q4 法說會逐字稿

Good morning. My name is Robert, and I will be your conference operator today. At this time, I'd like to welcome everyone to the fourth quarter 2016 earnings release and operations update for Oasis Petroleum.

(Operator Instructions)

Please note, this event is being recorded. I will now turn the call over to Michael Lou, Oasis Petroleum's CFO to begin the conference. Thank you. Mr. Lou, you may begin your conference.

Thank you, Robert. Good morning, everyone. This is Michael Lou. Today we are reporting our year-end 2016 financial and operational results. We're delighted to have you on the call. I am 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 uncertainty 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 to adjusted EBITDA to the applicable GAAP measures can be found in our earnings release, and on our website.

We plan to file our 10-K today following this call. We will also reference our current 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. The team continued to execute on our operational and financial plans, making 2016 another remarkable year for Oasis. We ended 2016 on a high note, with our Wild Basin development and infrastructure programs firing on all cylinders.

The Wild Basin crude and gas infrastructure came online on schedule in October, and was completed on budget. We also closed on our 55,000 net acre acquisition on December 1. The acquisition, which we've already covered in some detail, materially increases our inventory in our core area, and is directly in line with our efforts to continue to build around our large consolidated acreage blocks.

There has definitely been some harsh weather in Williston, especially the back half of December, and it was a real challenge. The team did an outstanding job working through it, as the Basin saw significant snowfall, leading to some road closures and shut-in production.

While some have reported material losses related to weather, our fourth quarter production of 53,200 barrels of equivalent a day, was in line with our guidance, further demonstrating the value of our infrastructure investments in OMS over the last several years. OMS remains an important strategic and differentiating asset for Oasis, and we plan to continue investing in infrastructure that allows us to increase cash flow and shareholder value, and manage our business risk. Our production was back at 62,000 BOEs a day exit rate that we had previously discussed for the very first week of January, as weather subsided.

We've already increased completion activity, and are on track to grow volumes by 16% to 72,000 BOEs a day by year-end 2017, and by another 15% to 83,000 BOEs per day by year-end 2018. Our operating plan is expected to generate free cash flow at the current strip.

We're able to grow production due to continued strong performance of our high intensity wells, which Taylor will go into in more detail momentarily. With that, performance supplemented by that of other operators, our core inventory continues to grow. And with all the work we've been doing through completion design and acquisitions, we now have over 10 years of inventory in the core. And with further activity outside of Wild Basin, we expect to the areal extent of the core will continue to grow.

Clearly, the macro environment in 2015 and 2016 presented us with numerous challenges. I couldn't be more proud of the way our team charged the storm. As I've told many of you, the companies that make it other side, will come out stronger, and we have clearly done that through quality of our human and capital resources, along with management of our balance sheet. The team made meaningful strides in capital and operating efficiencies through cost reductions, and well performance improvements that simply seemed impossible just two years ago.

Additionally, all of this progress has been substantially advanced by our vertical integration. I can't stress enough the importance to us, of OWS, our internal frac business, and the synergies we've realized through that team's hard work, in conjunction with our completion engineers. It has been remarkable to watch, and that group will be a key focus for us going forward, especially in the face of escalating service costs. Our decision years ago to enter the business has clearly paid dividends, in terms of ensuring service availability, quality, and cost.

Lastly, even in a low oil price environment, we were able to maintain access to capital, preserve liquidity, and strengthen our balance sheet. As we now begin to work our way back up, to a more normalized activity level, Oasis is truly in great shape. We will be careful to maintain our productivity and culture of innovation, as we -- that we have created. As the industry rebounds, we expect to see increased competition from many services, and with that will come some level of cost inflation in 2017.

Our strategy of vertical integration investment in infrastructure and the proven track record of our team will position Oasis to continue to differentiate ourselves in this next chapter. With that, I'll turn the call over to Taylor.

Thanks, Tommy. As Tommy mentioned, we're seeing very encouraging results from our latest round of completion testing in Wild Basin. We now have eight months of data on the 20 million pound slickwater job we brought online in June, and we brought three 10 million pound slickwater wells online in the fourth quarter. All four wells have begun to clearly differentiate themselves, from our four million pound completions in Wild Basin, and we feel the higher well performance supports the incremental capital for these bigger jobs.

Accordingly, we are shifting our completion program to higher sand loads, with an average of 10 million pounds per well, or 1,000 pounds per lateral foot, across 50 stages in 2017. A 10 million pound job currently costs about $6.5 million, compared to our current $4 million pound job at about $5.5 million. We are currently, and we're still early in this latest generation of completion techniques, and as a result, our knowledge base will continue to evolve, and we will adjust stimulation accordingly. But we feel results keep getting better, and economics suggest that the larger jobs are justified, since productivity and EURs are at least 25% higher, as illustrated on page 5 of the presentation.

While our average job will be 10 million pounds, part of the mix will include testing higher sand loads, including 20 million and 30 million pound frac jobs. We were excited about the response to larger sand loadings that we have seen in the core, and we're equally excited for the prospects, as you work outside the core. Keep in mind, that all of our inventory in EURs are based on four million pound frac jobs at this point.

We believe, that as we begin to test larger jobs in areas outside of the core, we will be able to further improve economics and expand the core area. With 770 locations in the core, with sub $40 WTI break-even prices, and 844 locations with sub $45 WTI break-evens, we have over 21 years of inventory that compete head-to-head with any top basin in North America. The balance of our inventory of 1,459 locations have break-evens ranging between $45 and $55 WTI, and we expect that continued frac design work would improve the economics of this inventory as well.

I'd now like to transition to the plan for 2017, that we highlighted in our press release. We plan to spend $605 million in capital in 2017. Drilling and completions is expected to total $410 million, which includes the well costs described earlier, and about 10% inflation.

We already have two frac crews running, with OWS focused in Wild Basin, and a third-party crew working in the Indian Hills. We expect to have the second crew working intermittently throughout the year. We have seen the pressure pumping market tighten a little bit, and our expectation is that it will continue to tighten as the year progresses.

Oasis has a natural hedge on rising pressure pumping costs with our current OWS crew, and through our ability to restart our second OWS frac crew when conditions warrant. Additionally, we are making arrangements to add two additional rigs mid year, and will average around three rigs for 2017. Since our larger frac jobs are taking a little longer to complete, we actually should be pretty balanced between spuds and completions in 2017, and we expect to complete 76 gross and 51.7 net operated wells during the year.

Exiting the year, we expect to be operating at a pace that fully utilizes two frac crews and four to five rigs. We also expect to spend about $20 million in non-operated capital this year. Together, this translates to a pretty smooth production growth trajectory, and a range of 65.5 to 70.5 thousand barrels of oil equivalent per day for the year, assuming an oil mix of about 78%.

We also have about $85 million of other capital, we plan to spend on the business. That includes items like capitalized interest, capital workovers, and facilities. This bucket is pretty similar to the amount we budgeted last year, but updated for current activity levels, and with a little extra for workover activity for the assets we acquired in December.

Lastly, we plan to spend $110 million on OMS and infrastructure capital. As Tommy said, our investment in that business was a major contribution to our success throughout the downturn. In 2017, we plan to accelerate some of the components of our Wild Basin gathering system. As we begin to do more work outside of Wild Basin, we will invest some additional OMS capital on our non-Wild Basin assets.

We've previously talked about exiting the year at $140 million annualized EBITDA run rate on OMS. With these incremental investments, and the Wild Basin system now online and fully operational, we expect that number to be more like $155 million of annualized EBITDA, by the time we reach the fourth quarter of 2017. With this capital plan and production growth profile, we believe we'll be cash flow positive at current strip pricing.

Finally, our net proved reserves at year-end 2016 increased over 40% over year-end 2015. While a good portion of these increases came from the terrific acquisition we closed in December, the balance speaks to the strong work the team is doing on increasing EURs, with high intensity completions, and improving capital efficiency across the Company. The capital efficiency is directly reflected in an all-time low F&D cost for the Company of about $7 per barrel of oil equivalent.

In closing, I want to commend the team. Our strong results reflect the hard work and innovation that the group has applied throughout the downturn. And this disciplined approach to our work will serve us well, as we rebound into 2017 and beyond. With that, I will turn the call over to Michael.

Thanks, Taylor. As you saw in our press release, the fourth quarter and all of 2016 exceeded the plans we set when we entered the year. We made significant strides to improving our financial and operational performance.

A few highlights include a highly accretive, well-capitalized acquisition, cash interest reduction of $20 million a year, significant well performance improvements, and successful higher proppant loading tests, growth in core and extended core locations, materially extending highly economic inventory life. Well costs, operating costs, differentials and G&A were all down in meaningful ways, and the successful build and launch of our Wild Basin infrastructure project.

This translates into the ability to grow over 15% for the next few years, while generating positive cash flow at current strip prices. The successful test well results, on top of the strong base well results cause us to get comfortable with increasing our exit rate expectations for 2017 and 2018 to 72,000 barrels of oil equivalent per day, and over 83 MBoe per day respectively.

We continue to expect to see LOE come down, driven by infrastructure, well performance, and lower water cuts in Wild Basin. Differentials are also expected to come down further, and average in the $3 to $4 per barrel range in 2017. Differentials will be driven lower by access to pipe, especially as DAPL comes online this year. Our gathering, marketing, and transportation expenses will be up a bit in 2017, although this will be offset by the advantaged realizations on oil and gas that our Wild Basin infrastructure brings us.

[On] capital expenditures, we're very close to the numbers that we have been talking about since our third-quarter call. Based on a $50 oil price, we talked about nearly doubling 2016 activity levels on the D&C side, and coming in around $400 million. So our $410 million D&C budget comes very close, although the complexion has changed to more higher proppant loading wells, which added about $75 million, and increased non-op spending based on the acquisition of about $20 million.

However, we also lowered the total number of wells to be completed from around 100 wells to 76 gross operated wells, which materially extends our inventory life. On non-D&C capital, we talked about around $[60] million which includes things like capitalized interest, capital workovers, and the facilities. The budget for this year is $85 million, which is up a bit for acquisition -- for the acquisition, both for one -- additional one-time workover on the acquired asset, and routine management of a larger base of production.

On infrastructure, we talked about $50 million to $70 million in capital, and we budgeted $110 million. Given some low hanging projects that we will be executing on with OMS, we will spend about $50 million more capital than we have been talking about previously. But we think the projects will add value quickly, and we have thus increased the expected exit rate on an annualized EBITDA basis to approximately $155 million for OMS. The additional projects include preparation for an accelerating program, acquisition-related work, and creating capacity for significantly improving well performance.

OMS and OWS will contribute about $60 million to $70 million of incremental EBITDA to our income statement, that many people forget about to include in our models. Overall Company G&A guidance is $95 million to $100 million this year.

On inventory, Taylor covered the increases that we have seen to our core and extended core inventory positions. I would note that on page 7 of our corporate presentation, you can see the 27% increase to core, and 19% increase to the extended core. In the quarter, we have not only added inventory from the acquisition, but we have started to move some of our extended core into our core inventory, based on well performance.

Importantly on page 5, you will see the potential positive impact of productivity of higher proppant loading jobs, with better proppant dispersion techniques, specifically in Wild Basin and the possible outperformance of our 1.55 MBoe type curve.

On page 6, you will note that our core area type curve, excluding Wild Basin, has also moved up, and is now higher than our old core type curve which included Wild Basin. So even as we move more inventory into the core, and we excluded the highly productive Wild Basin wells, our type curves have still moved up.

We will also be testing higher proppant loading wells in the extended core inventory, and will hopefully based on results, continue to move more inventory over time from our extended core to our core areas. On production guidance, while we have budgeted for more capital, we have not fully baked in the potential uplift of the higher proppant loading wells we'll be completing this year.

As we closed out to 2016, we want to congratulate our team for an incredible job that they did in lowering capital and operating costs, driving efficiencies across all business lines, improving financial metrics, significantly increasing core inventory life, materially improving well performance, and setting up Oasis to grow at extremely compelling capital efficiency metrics, while generating free cash flow over the next few years. With that, I'll turn the line back over to Robert, to open the line for questions.

Thank you.

(Operator Instructions)

Neal Dingmann, SunTrust.

Good morning, guys.

Hey, Neal.

Looking at slide, Tommy, it's slide 3, for you or Taylor. You talk about the press release, you guys are certainly very active, and it's certainly is paying off, when you add the two rigs in mid 2017, and potential to earn that other one in 2018. Can you talk about, just kind of looking at the general area, is there any -- do you already have it earmarked to where those three -- I mean, I know that's one is not until early 2018 -- where those three are designated to go, and kind of where you'll keep all of them working for the remainder of the year?

Sure. The additional rigs will be concentrated in the core, and they'll be spit between Alger and Indian Hills.

Okay. Okay. And then just on that, you mentioned in the press release also about, that one of your spreads is working outside, a third-party working outside the Wild Basin. Can you talk -- will you bring back that second spread proprietary spread of yours anytime soon, and will you keep this third spread working outside of that, as it is now?

So what we plan to do for the year is to have, we'll have one frac crew, our internal frac crew working steady throughout the year, and then, the second crew will be intermittent. So it's running right now, it's a third-party. We're going to have a gap in the middle of the year, and then likely pick up again, with that second frac crew later in the year.

So it will end up just being two crews. And then we'll make a decision about whether we go ahead and pick up our second frac crew, as we pick up activity again in the second half of the year. And it will be based on the market conditions, and where costs have gone. Certainly, where we're seeing things right now, like we've talked about it's -- costs have tightened a bit on the frac side, early in the year. And if things play out like we think, and it continues to accelerate, then we'll sure look at picking up our crew, because we can offset those increases.

Neal, that second crew is Indian Hills. And then, we'll go up to Eastern Red Bank. So one of the good thing is, is having those DUCs there for us to execute on now, gives us more data on higher intensity or higher prop completions in some of those areas outside of Wild Basin. So we should get some really good data there.

Great details. Thanks, guys.

You bet.

David Deckelbaum, KeyBanc.

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

Morning.

I'm just curious on the incremental OMS spend. As you guys sort of earmarked $110 million or so this year. I understand it's accelerating Wild Basin. Can you give a sense as to how much of that capital is building out, outside of Wild Basin. And I guess as we think about accelerating outside of Wild Basin, with rigs going into 2018, where should we think about sort of future midstream spending being?

Yes. So a good question, Dave. About $30 million of that is going to be spent outside of Wild Basin this year, and you're exactly right.

As we start to continue to pick up activity outside of that Wild Basin area, there is some work to do on kind of the legacy system, to make sure that we can handle the volumes, but also handle kind of the better well productivity that we're seeing. So making sure that we can handle that appropriately. Next year, if you want to think about that midstream capital, $80 million is probably a good number to think about and call it, around one-half of that in Wild Basin, and one-half of that in our legacy areas.

I appreciate that, Michael. It's helpful. And Taylor, you could just help me just on the -- I guess, can you give an idea of -- at this point, the average is 10 million pounds loaded jobs. I guess, like in Wild Basin, is the bias higher with the 20 million jobs? And I guess, are you going to be testing north of 10 million outside of the Wild Basin? And if you could kind of give a sense of to, how much longer you believe your sort of cycle times are, on a 10 million or 20 million pound job versus your 4 million pound job?

Okay. So in Wild Basin, I've talked about overall, in the program, we're going to average 10. And we've got quite a few wells that we're going to do these 20 million and 30 million pound jobs. So I think it's something like it's around 8 to 10 wells. We've only got one of the bigger wells in Wild Basin at this point, as you see on the graph in the presentation. That well is still flowing. It is nine months in, hadn't turned over yet, so great results.

As we do more of these, and get more confidence around the uplift versus the cost, and if we continue to see that relationship, then we'll continue to move the average sand loadings up. So we're -- we just don't have a lot of the 2,000 and 3,000 pound foot lateral jobs yet. But as we get that data, and if the results play out like we're seeing, like I said, we'll step it up.

When you get outside of Wild Basin, we are doing a 10 and 20 million pound frac jobs. Some of that in Indian Hills, some of that in Red Bank like Tommy talked about, and then we'll be doing some of that over in Alger as well. So the plan is to step up the sand loadings, really across the position as we step out.

And in terms of cycle times, going from a 4 million to a 10 million pound job, or 4 million pound job, we got them down to -- it was roughly four days to do one of those fracs. You go to a 10 million pound job, maybe you're adding a day or something like that onto the job.

Appreciate that, Taylor. Thank you, guys.

You bet.

Michael Hall, Heikkinen Energy.

Thanks. Good morning.

Hey, Michael.

Congrats on having a good year behind you all.

Thanks. (Multiple speakers)

I guess, I just want to keep on the completion side of things for the moment. How do you think about the potential for these higher jobs to change the break-evens across the portfolio -- do you have any of the break-evens kind of broken out by area? What you think you're playing for, as it relates to the ability to bring those break-evens lower, with these higher sand loading?

Yes, I think that's one of the things Michael talked about in his remarks, and the things that we're really excited about is ability, not only to drive that break-even lower in the core, but especially to be able to pour -- I mean, to pull more of the extended core into the core. And we did that with part of Red Bank, got some of those wells with these completions in a sub $40 WTI break-even. So we think with these bigger loadings, we'll be able to do more of that. And then, same on the fairway to the extended core doing, doing bigger fracs. Hopefully, we can continue to build that extended core as well.

And as you think about kind of core, is it the EUR threshold that you're most focused on, or the break-even, or kind of some combination thereof? I mean, you talk about the EURs being bumped up 25% more?

Really what we've done this time, Michael, is categorize it by break-even. So if we can take, while we want to have big EURs, but right combination of EUR and well costs, if we can pull that into that sub $40, then we can expand that core out further.

Got it. And as we think about costs of moving from 10 million pounds, to 20 million to 30 million pounds, I think you gave us the 10 million versus 4 million, is it pretty linear as we move up to 20 and 30? Or is there any kind of savings or scale if you will, that offset the increase, as you move higher and higher?

At this point, it is early in terms of doing those 20 million and 30 million pound jobs. We don't have a lot of them under our belt. So we're saying it's going to be pretty linear in terms of cost increase, similar to kind of [$1 million], as you bump up to each one.

But we think, as we do more of those jobs like we have in the past, we'll get those costs down and we'll be more efficient. So don't hang your hat on those numbers at this point. We, as we do more of them this year, we'll be able to give you a better number. And like I said, I think we'll get more efficient and pull that increase down.

Okay. That's helpful. And then, I guess, last on my end, how sensitive are the economics of these higher jobs to sand loadings -- or sorry, sand pricing? How do you think about that?

Yes, the sand pricing is important. Obviously, a significant part of the frac job, but you've also got an equal increase in cost that's coming from water.

You're going from a -- the base job, which was about 200,000 to 220,000 barrels of fluid, the old 4 million pound job now with these 10 million pound jobs, you're over 300,000 barrels of fluid. Now that you're at 20 million and 30 million, that grows even more so. Sand is an important part of being efficient on the water side of the business is important to us as well.

Yes, and just add a little bit to that, Michael, so if you think about 6 million pounds more of prop at $0.05 a pound, the sand itself is about $300,000 difference between the 4 million pound job and the 10 million pound job. And remember of that $0.05 of sand costs, a large portion of that's around transportation. We think that the Bakken is pretty advantaged on the transportation side of that. So while sand [mine gate] prices may go up a bit, we think the transportation will behave a little bit better.

And then, as Taylor mentioned on the water side, that's also an important piece that we think has materially changed since 2014, when a lot of that water was being moved by trucks. Today it's, a lot of that freshwater, most of it's being moved by pipe. So we don't think that that cost will go up significantly at all on the freshwater side.

That's all. Super helpful. I guess, one more if I could, actually. How are you treating these new jobs in the guidance, as it relates to on the production side of things? Obviously, it's early days like you said. I'm just trying to think maybe how you [risked] guidance this year, relative to years past, given kind of the earlier stage we're in, in terms of data for these 10 million pounds type jobs?

Yes. And Michael, we said it a little bit in the prepared remarks, but it's a good question. We did include, obviously, all of the capital for the higher intensity completions.

It's about $75 million of D&C capital to go to these larger jobs. We have included some increase on the productivity side, but certainly, not the whole 25% that you see on the pages in the presentation.

Cool. Thanks. Sorry I missed it. I appreciate it, guys.

Thanks.

Biju Perincheril, Susquehanna.

Hi, good morning. In the Wild Basin, you have tested some completions with the gel coated sands, and I was just wondering if that is something that you expect to get production uplift from, or is that strictly looking for lower costs, and if there is any early data that you can give whether, on the cost side or production side?

Yes, we did some tests last year with gel coated sand, and it's -- the whole goal of that was to be able to increase sand loadings, and reduce the amount of fluid that we were pumping in doing the jobs.

We did a handful of them, and the results were really in line with the other wells, although we were able to -- while that proppant cost more because of the coating, we were able to offset some of that with the reduced cost. At this point, we're still evaluating the results, and we'll determine if we are going to test more of that in the coming year.

Okay. That's helpful. So I guess, it's -- the jury is still out on whether or not you're going to be fully offset the higher proppant costs at this point?

Yes, we're still evaluating whether it's something want to continue ahead with. The big things that we came away from last year's program, that one we're interested in, and we're going to continue to evaluate. But it's better dispersion of our frac through increased stages. So we've gone from a 36 to a 50 stage job, and then increased sand loadings. Those are the two big hitters.

All right. I am sorry if I missed this, did you give the timing on when you will be testing the higher intensity completions on the, I think in the Red Bank area?

Yes. The Red Bank fracs will be in second quarter, and so we will be fracking them here in near future. We got the frac crew right now in Indian Hills, and once it gets done there, we've got 11 wells there, then we'll move up to Red Bank, and we will start doing the fracs. It will probably be kind of April, May time frame, as we're fracking, and then get early results this summer.

Great. All right. Thank you.

Thanks.

Mr. Ron Mills, Johnson Rice.

Good morning, guys. A question as we try to compare slide 5 to slide 7, in terms of your EURs per location. The core EURs of 1.2 million barrels, is that a mix of -- is that just the difference in the mix of the Wild Basin and the core to get to the 1.2 million barrels?

Yes, that's correct. It's the Wild Basin EURs, plus everything outside the core. So if you combine the type curves that you see on page 5 and 6, and then take a weighted average of that, you get to that 1.2.

And based at least on the early results in Wild Basin, it looks like there's obviously maybe some upside versus the 25% you highlighted. But is there any, or do you have any information on offsetting activity in some of your core and extended core areas, that are delivering even higher recoverabilities through the employment of higher proppant, that you're able to benefit from other people's money?

Sure, Ron. Yes, we look at all the other operators' results in the basin, and are focused on everybody that done these higher sand loadings, in both inside and outside the core, you are seeing some really good results. And based on that, like you said, there is a bias, based on what we've seen in our wells, and in some other operators to be above that 25%. Now we'll see how it plays out, as we do more of these but we are excited about the results we're seeing both in-house, and what other guys are doing as well.

And then, I guess, where I'm going with this, particularly as I look at the extended core, you've had some activity in both Red Bank and Painted Woods area that are showing at least early data results similar to your core. Over time do you expect to see a lot more of this extended core inventory shift up to your quote/unquote core?

Yes. That's really a big part of the play for us this year, and next year as we test, just like you said of these bigger jobs, not only in Red Bank and Painted Woods, but at some point, get them pushed out to even Montana. We're hopeful that we can start pulling more of that extended core into our core, just like we did in East Red Bank this year.

Great. And then two other quick ones. One on OMS, the increased spending, and the associated increased EBITDA, is one of the other benefits there, is did your OMS system somewhat insulate you in the fourth quarter against some of the severe weather, and can that continue to provide some insulation into, relative to maybe some of your peers in tough weather conditions?

Yes, absolutely. And we've talked about this a lot, Ron, it's the less trucks, the better. And so, if it's, water, produced water, oil, freshwater for fracs, the more you can do across pipe, and not on trucks -- I mean, you get enough snow, and trucks can't move, right? So the more we can do through pipe, the better.

Great. And then, just so Michael didn't get left out, on the differential guidance, the $3 to $4 through the year, do you have any sense of how that may look through the year? Should it remain similar to the $4-plus range in the early part, and can start moving down in the back half, to once you have the impact of DAPL, and where do you think it gets to, as you think for 2018 and beyond?

Yes. And I think you're exactly right there, Ron. It is going to start probably on the higher side of that range at the beginning of the year, but will move towards the lower side when DAPL comes on. And DAPL has called for line fill, and so that should be up and running here, over the next couple of months, which will be huge takeaway capacity for the basin as a whole. So that should meaningfully tighten differentials, and we're starting to see that happen, even as they call for, as they called for line fill already.

Perfect. Thank you, guys.

Thanks, Ron.

David Tameron, Wells Fargo.

Good morning.

Hey, Dave.

Michael, just before we leave DAPL, can you walk me through -- I mean, obviously everybody got their own differential number, right, out there. And most people are citing somewhere in that $2 to $3 range. But as you know, any time we see a pipeline start up, there's always a dynamic impact somewhere else, that nobody ever appreciates until it's up and running, right? So I'm just trying to think about DAPL specifically, as it relates to your volumes. How much of it's a direct impact, how much of it's just an overall uplift to the entire basin? I'm just trying to think of some of the details, as far as the transfer points and --

Sure. No, it's a good question. I think what will happen is, DAPL is a large system, with numerous take points throughout basin, so it's actually going to help differentials throughout the basin. And it's a couple of things. One, DAPL will come online, and usually when you have a big project like that, you have significant commitments from E&P producers and downstream producers to ship across that system. So it's going to likely be pretty full, as it comes online.

Well, that production has to come from somewhere. So you have a pipeline that's nearly half the production of the basin coming online. Well, the other takeaway, whether it be other pipes or rail, those also have long-term commitments. Who is going to see the biggest benefit are the people that have less long-term agreements and more short-term agreements where they can move their barrels from, call it, rail or other pipes to DAPL and go to the cheapest cost. And then everybody's going to have to lower costs to try to get barrels onto where ever their dedications are.

So we think it's going to be an overall impact to the basin, not necessarily those that are just shipping on DAPL. It is just provides a lot of competition for your barrels across the basin.

Okay. Yes, that's part of where I was going, so the spot price could get -- [you guys could be] bidding some pretty low numbers, just to get it out of the basin. Okay. Okay.

So the good thing for us, is we have very few of our barrels locked into long-term agreements. So part of the strategy of our marketing team, was that we thought there would be more takeaway capacity than production in the basin. And in that situation, we'd want to be more short-term oriented, and we think that that's really playing out to our advantage.

Okay. And just back to the higher proppant jobs, if I start, if I start thinking about outside Wild Basin, obviously, it's very good rock there. Is there any reason, when you start thinking about outside the extended core that the higher frac jobs, what work or kind of what's the difference in the rock as far as the willingness to accept the higher frac, and the more sand, and the bigger frac? Can you just address that?

Yes. So we really do not see a reason why, you're not going to get similar uplift as you go outside the core. Now in Wild Basin, as we've talked about in the past, deepest part of the basin, a little higher pressures, higher gas/oil ratio. So a lot of energy in that reservoir, and really good oil charge.

So we've seen great uplift, but we expect, and we've already seen this with some third-party jobs, as you get outside of Wild Basin, into the other parts of the core, and seen similar things, as you go into the extended core. So the reservoir in general, as you go to the West for example, then so you don't have quite as thick of a column, but still think the higher sand loadings will give you nice increases, as you get away from the core.

Okay. And Taylor, was there any change in the way you approach it from artificial lift standpoint, with the different completion jobs, kind of thinking outside the core?

Yes. You really have all the same options at your disposal, and we've used a mix of artificial lift, depending on where we are. So anything from gas lift, where we have a lot of concentrated completions in an area, and good gas supply. Used a lot of electric submersible pumps, so ESPs. And then, so larger bean pump units like Rotaflexes that can move more fluid, so you really have all those at your disposal.

As you get further away from the deeper, gassier part of the basin, ESPs tend to be a little easier to deal with, because they can struggle a little bit sometimes with high gas, so we may use a bit more of ESPs in some of those areas that are a little more distal.

Okay. And just specific to the completions jobs, if you use higher completion job in the extended core, to pull on the reservoir a little harder, would that imply a sooner lift job, or am I over-thinking that?

You mean in terms of conversion to artificial lift?

Yes. Yes.

Yes, really we've seen, as we've done these bigger jobs, it's the other way. You're really charging the reservoir with the big sand, and especially the big fluid volumes. So wells are tending to flow longer. And that [John Tree] well, the 20 million pounder in the Wild Basin, is a great example. It's nine months in, and is still flowing at a nice pressure.

And so, we think we'll continue to see that in other areas. There is actually a well that we did at a high sand loading over in North Alger, that has flowed for a longer period of time than the prior well, so I think that'll play out, as we do these bigger frac jobs even outside the core.

Okay, and last one for me. Obviously, realizing that -- well, not obvious -- but type curves and (inaudible) D&M reserve bookings don't always match up, just kind of the conservative nature of the reserve firms. Can you talk about what you're -- what they're allowing you to book right now in some of these? And I'm just thinking about the 12 well package you talked about before, your first -- not necessarily the 2,000, 1,800 type curves, but the package before that, when you're tracking the [1.5] like what are they -- what are you guys booking on a per well, for some of the new drills out there?

So keep in mind, that our reserves, and they're done by D&M, and they actually do an independent reserve report, so they're not auditing our results.

Yes.

When you look at the way they [book] their wells in general, we have ups and downs, but generally they are in line with what we booked.

Okay. All right. Thanks. Thanks for all the color.

You bet. Thanks, Dave.

James Spicer, Wells Fargo.

Hey, good morning. Just wondering if you could spend a minute on the balance sheet. Where are you today, versus where do you want to be on, leverage or what ever other metrics you look at? And given that your bonds are callable, does that provide any opportunities, particularly in anticipation of generating some free cash flow?

Sure, James. Look, the balance sheet, there was a lot of improvement last year on the balance sheet, and given that we're set up as you mentioned, in terms of generating free cash flow here, we have some options to think about, as we go into the year.

So from a debt to EBITDA standpoint, think about we've always kind of said that we'd like to get in a normalized oil price over time, back under 2 times debt to EBITDA. We're still a little ways from that, but we think we can comfortably grow back into that, given the significant growth that we're going to see over the next couple of years.

And then, what we'll have to figure out in terms of the free cash flow, we are going to generate some very strong free cash flow over the next couple of years, given this growth profile call it, in a strip type price. And we have a couple of options there. We can continue to increase our well activity on the E&P side of things, grow production. That will help our metrics, or we could pay down the revolver, or like you said, call in some of the notes, and reduce top line or aggregate debt. All of it will be obviously very accretive to balance sheet. And so, we'll continue to figure out which one's the better option at any given point in time, as we move forward, and see that the cash flow come in.

Okay. Great. Great. That's helpful. And then secondly, and obviously, your infrastructure investments have been quite strategic, and there's some good growth ahead, especially this year. Where are you guys stand currently on just the concept of monetization?

I think we're still in the same position that we've been. To the extent that we can see a large arbitrage of value between monetizing midstream versus where we're valued on the E&P side, we're going to take advantage of that. And the good thing is that, the midstream capital that we spent last year, we spent overall in our capital budget, basically within cash flow.

And the next couple of years, we're going to be generating free cash flow. So there's not as much of a need to monetize. But we are certainly looking at it, and to the extent that you see midstream multiples getting stronger -- and we have seen that over the last 6 to 9 months -- we have a number of options that we'll continue to evaluate over time.

But I'd also add, that relative to where we were last year, having the Wild Basin infrastructure up and running with oil, gas, water, all that moving through the system, and the spend behind us, it removes a lot of the range of uncertainty that people would price risk into. And so, having all of the, what I call the yes buts behind us, is helpful in terms of valuation of the asset.

Yes. Yes. Understand. Thanks a lot.

John Nelson, Goldman Sachs.

Good morning, and thank you for taking my questions.

Hey, John.

I just, I had a question on the higher intensity completions, specifically, the 20 million pound Wild Basin that you guys have on your slides. I'm a finance guy, so I don't want to get too far over of my skis here, but is the well bounded on kind of both sides? I guess, what I'm try to get at is, to see if any of the outperformance is maybe stealing from potential offset locations, or is this purely kind of how we should think about a repeatable well?

Yes, the well is -- that particular well is a lease line well. So it's got wells tightly -- in what we're doing in our regular spacing on one side, spacing a little bit bigger on the other. But we think it is going to be representative. Now that's a 10 million, I mean, 20 million pound well. I think a good comparison point is a10 million pound well. And so, when you look at the wells that we've done are 10 million pounds, those are more entrenched within all the regular spacing. And you can see that the performance on that 10 million pound well, it's kind of similar, in terms of long flow life, not turning over, and not seeing an inflection point early. So we think you're going to have good results.

Okay. That's really helpful for a poorly worded question. And then, just to be clear on kind of the inventory changes, it looks just from eye-balling it, that Eastern Red Bank, moving to the core in Montana, moved into the extended fairway, is that the majority of what drove the increases? Or were there other kind of moving pieces?

That's the primary moves, that's a good characterization.

Okay. And then, the last one, just housekeeping. Big ballpark 2018, five rigs, that's roughly 125 gross wells, is that kind of a fair way to think about it?

It may be a little bit high, but --

Yes, a little bit under that, but you're in the right ballpark.

115, 120? Okay. Perfect. Thanks. Congrats on the quarter, guys.

Thanks, John.

Joseph Byrnes, Citigroup.

Hi, good morning, everyone. This is Jeanine Wai. So I guess, in terms of -- you made some comments about trying to pull some of the extended core forward into the core category. And then, I think you also mentioned that the additional rigs that you're adding will be split between Alger and Indian Hills. So just kind of wondering what you need to see to really get after the extended core, in order to try to prove up more of that, and accelerate shifting some of the locations between that [bucket] into the core.

So as Tommy mentioned, we're doing some of that early, we're fracking some wells up in Red Bank, and talked about it would kind of be April/May time frame, when we get on those wells. And so, as we see results from that work, there's results from other operators we're looking at.

And then we've are also working on some pilots that we're going to do additionally in Red Bank, and then in Painted Woods, and eventually in Montana as well. And that work will stretch out 2017 and into 2018. As we pull all of that stuff together, it's going to give us the confidence and the data to continue to move more of that extended core into the core.

Okay. The pilots are interesting. What kind of things are you primarily targeting? I think you just addressed some of the issue on going from single test to full development, with all 10 million pound fracs? Or are you testing -- like what other things are you changing in the new pilots?

Yes, the main thing is going to be the increased stage count relative to what we've done historically, so 50 stages. And then, the higher sand loadings, and so it will be going from the old wells that were 4 million pounds [sell] jobs [10s million] and up.

Okay. And then last one for me. Just wanted to circle back. You mentioned that the current production forecast doesn't include the 25% uplift in the EUR. And then, I think you might have said it before -- and I am not sure if I caught it -- that you did include some [risking], but not the full 25%. And I just wanted to kind of circle back, to kind of get your thoughts on that?

Yes, we've got some of the production baked in, but not the full 25%. That's exactly right.

So is it more -- like the 5%, 10% range, or just too early to say?

It is above 0% and less than 25%.

Okay. We can work with that. (laughter)

All right.

Thanks for taking my call.

Thanks.

This concludes our question and answer session. I would now like to turn the conference over to Tommy Nusz for any closing remarks.

Thank you again for joining our call. The quality of our team and our assets, in conjunction with our ability to manage risk through vertical integration has served us well through the downturn. And just as importantly, has put us in a great position going forward. Thanks again for being with us today.

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