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. All participants will be in listen-only mode. Should you need assistance, please signal for a conference specialist by pressing the star key followed by zero. After today's presentation, there will be an opportunity to ask questions. To ask a question, you may press star then one on your touchtone phone. To withdraw your question, please press star then two. Please note, this event is being recorded. I 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'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 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. 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 1st. 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 in the back half of December. 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 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 BOE 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 BOE a day by year-end 2017, and by another 15% to 83,000 BOE per day by year-end 2018. Our operating plan is expected to generate free cash flow at the current strip. We were able to grow production due to continued strong performance of our high-intensity wells, which Taylor Reid 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. With further activity outside of Wild Basin, we expect the aerial 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 to the other side will come out stronger, and we have clearly done that through the 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. 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 frack business, and the synergies we've realized through that team's hard work in conjunction with our completion engineers. It's 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 assuring service availability, quality, and cost. 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 that we have created. As the industry rebounds, we expect to see increased competition from many services. 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 slick water job we brought online in June, and we brought three 10-million-pound slick water 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 for 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 four-million-pound job at about $5.5 million.
We are still early in this latest generation of completion techniques, as a result, our knowledge base will continue to evolve, and we will adjust stimulation accordingly. We feel results keep getting better, and economics suggests that the larger jobs are justified since productivity and EURs are at least 25% higher, as illustrated on page five of the presentation. While our average job will be 20 million pounds, part of the mix will include testing higher sand loads, including 20 and 30-million-pound frac jobs. We're excited about the response to larger sand loadings that we have seen in the core, and we are equally excited for the prospects as you work outside the core. Keep in mind that all of our inventory and 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 breakeven prices and 844 locations with sub-$45 WTI breakevens, we have over 21 years of inventory that competes head-to-head with any top basin in North America. The balance of our inventory of 1,459 locations have breakevens 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 cost 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 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 operator 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 in a range of 65.5 thousand barrels of oil equivalent-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 in 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 proof 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. Their strong results reflect the hard work and the 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'll turn the call over to Michael Lou.
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 profit loading tests, growth in core and extended core locations, materially extending highly economic inventory life. Well cost, operating cost, differentials, and G&A were all down in meaningful ways, and a 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 three to four dollar 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 advantage realizations on oil and gas that our Wild Basin infrastructure brings us.
On capital expenditures, we are 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. Our $410 million D&C budget comes very close, although the complexion has changed to more higher profit loading wells, which added about $75 million and increased non-op spending based on the acquisition of about $20 million. 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 facilities.
The budget for this year is $85 million, which is up a bit for the acquisition, both for 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 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've been talking about previously. 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 the incremental EBITDA to our income statement that many people forget about to include in their 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 seven of our corporate presentation, you can see the 27% increase to core and 19% increase to the extended core. In the core, 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 five, you will see the potential positive impact of productivity proppant loading jobs with better proppant dispersion techniques, specifically in Wild Basin, and the possible outperformance of our 1.55 BOE type curve.
On page six, 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. Even as we moved 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 close out 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. We will now begin the question and answer session. To ask a question, you may press star then one on your telephone keypad. If you're using a speakerphone, please pick up your handset before pressing the keys. If your question has been addressed, you may withdraw from the queue by pressing star and then two. At this time, we will pause momentarily to assemble our roster. The first question comes from Neal Dingmann of SunTrust. Please go ahead.
Morning, guys.
Hey, Neal.
Looking at slide, Tommy, it's slide three for you or Taylor. You talked about the press release. You guys are certainly very active, and it's certainly paying off. When you add the two rigs in mid 2017 and potential to add that other one in 2018, could you talk about, just looking at the general areas, do you already have earmarked to where those three, I know that one's not until early 2018, where those three are designated to go, and 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 split between Alger and Indian Hills.
Okay. Just on that, you mentioned the press release also about that one of your spreads is working outside, the third party working outside the Wild Basin. 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?
What we plan to do for the year is we'll have one frac crew, our internal frac crew, working steady throughout the year, and then the second crew will be intermittent. It's running right now. It's a third party. We're going to have a gap in the middle of the year, then likely pick up again with that second frac crew later in the year. It'll end up just being two crews. 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. It'll be based on the market conditions and where costs have gone. Certainly where we're seeing things right now, like we've talked about, costs have tightened a bit on the frac side early in the year.
If things play out like we think, and it continues to accelerate, we'll sure look at picking up our crew because we can offset those increases.
Neal, that second crew is Indian Hills, and we'll go up to Eastern Red Bank. One of the good things 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. We should get some really good data there.
Great details. Thanks, guys.
You bet.
The next question comes from David Deckelbaum of KeyBanc. Please go ahead.
Morning, Tommy, Taylor, Michael. Thanks for taking my questions.
Morning.
Just curious on the incremental OMS spend. As you guys 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 outside of Wild Basin? Then I guess as we think about accelerating outside of Wild Basin with rigs going into 2018, where should we think about future midstream spending being?
Good question, Dave. About $30 million of that is going to be spent outside of Wild Basin this year. 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 the legacy system to make sure that we can handle the volumes, but also handle the better well productivity that we're seeing. 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. Call it around half of that in Wild Basin and half of that in our legacy areas.
I appreciate that, Michael. That's helpful. Taylor, if you could help me. Can you give an idea of, at this point, the average is 10 million pounds loaded jobs. I guess, in Wild Basin, is the bias higher with the 20 million jobs? I guess, are you going to be testing north of 10 million outside of Wild Basin? If you could give a sense of how much longer you believe your cycle times are on a 10 million or 20 million pound job versus your four million pound job.
Okay. In Wild Basin, I talked about overall in the program, we're going to average 10. We've got quite a few wells that we're going to do these 20 and 30 million pound jobs. I think it's something like 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's still flowing. It's nine months in, hadn't turned over yet. Great results. As we do more of these and get more confidence around the uplift versus the cost, if we continue to see that relationship, we'll continue to move the average sand loadings up. We just don't have a lot of the 2,000 and 3,000 pound foot lateral jobs yet.
As we get that data, 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 10 and 20 million pound frack jobs. Some of that in Indian Hills, some of that in Red Bank, like Tommy talked about. We'll be doing some of that over in Alger as well. The plan is to step up the sand loadings really across the position as we step out. In terms of cycle times, going from a four to a 10 million pound job, or a four 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.
Got it. Appreciate that, Taylor. Thank you, guys.
You bet.
The next question comes from Michael Hall of Heikkinen Energy. Go ahead.
Thanks. Good morning.
Hey, Michael.
Congrats on having a good year behind y'all.
Thanks.
Hope you hit the fun. I guess, yeah, I just wanted to keep on the completion side of things for a moment. How do you think about the potential for these higher jobs to change the breakevens across the portfolio on Slide 78, you have the breakevens kind of broken out by area. What do you think you're playing for as it relates to the ability to bring those breakevens lower with these higher sand loading?
I think that one of the things Michael talked about in his remarks, the things we're really excited about, is the ability not only to drive that breakeven lower in the core, but especially to be able to pull more of the extended core into the core. We did that with part of Red Bank, got some of those wells with these completions in a sub-$40 WTI breakeven. We think with these bigger loadings, we'll be able to do more of that. Then, same on the fairway to extended core, doing bigger fracs. Hopefully, we can continue to build that extended core as well.
Is it the EUR threshold that you're most focused on, or the breakeven, or some combination thereof? You talk about the EURs being bumped up 25% or more.
What we've done this time, Michael, is categorized it by breakeven. If we can take We want to have big EURs, but the right combination of EUR and well cost, if we can pull that into that sub-$40, we can expand that core out further.
Got it. As we think about costs of moving from 10 million pounds to 20 million-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? Are there any kind of savings or scale, if you will, that offset the increase as you move higher and higher?
At this point, it's early in terms of doing those 20 million and 30 million pound jobs. We don't have a lot of them under our belt. 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. 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. Don't hang your hat on those numbers at this point. 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. I guess last on my end, how sensitive are the economics of these higher jobs to sand loadings? Sorry, sand pricing. How do you think about that?
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 the base job, which was about 200,000 to 220,000 barrels of fluid, the old four million pound job. Now with these 10 million pound jobs, you're over 300,000 barrels of fluid. That you go to 20 and 30, that grows even more. Sand's an important part of it, but being efficient on the water side of the business is important to us as well.
Yes, just to add a little bit to that, Michael. If you think about six million pounds more of prop at $0.05 a pound, the sand itself is about a $300,000 difference between the four million pound job and the 10 million pound job. Remember that 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. While sand mine gate prices may go up a bit, we think the transportation will behave a little bit better. 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, a lot of that fresh water, most of it's being moved by pipe.
We don't think that cost will go up significantly at all on the fresh water 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've said, just trying to think about how you've maybe risked guidance this year relative to years past, given the kind of earlier stage we're in terms of data for these 10 million pound type jobs.
Yeah. Michael, we said it a little bit in the prepared remarks, but it's a good question. We did include, obviously, all the capital for the higher intensity completions. That'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. Appreciate it, guys.
Thanks.
Thanks.
The next question comes from Biju Perincheril of Susquehanna. Go ahead.
Hi. Good morning.
Good morning.
In the Wild Basin, you have tested some completions with the gel-coated sands, I was just wondering, is that something that you expect a production uplift from, or is that strictly looking for lower cost? If there is any early data that you can give on whether on the cost side or production side?
We did some tests last year with gel-coated sand, the whole goal of that was to be able to increase sand loadings and reduce the amount of fluid that we were pumping and doing the jobs. We did a handful of them, the results were really in line with the other wells. Although that proppant costs 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, we'll determine if we're going to test more of that in the coming year.
Okay. That's helpful. I guess jury's still out on whether or not you're going to be able to fully offset the higher proppant cost at this point, right?
Yeah. We're still evaluating whether it's something we want to continue ahead with. The big things that we came away with from last year's program, that one we're interested in, we're going to continue to evaluate. It's better dispersion of our frac through increased stages. 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'm sorry if I missed this. Did you give a timing on when you will be testing the higher intensity completions in the Red Bank area?
Yeah. The Red Bank fracs will be in second quarter. We'll be fracking them here in the near future. We got the frack crew right now in Indian Hills, and once it gets done there, we've got 11 wells there, we'll move up to Red Bank, and we'll start doing the fracks that are probably April, May timeframe as we're fracking. Get early results this summer.
Great. All right. Thank you.
Thanks.
The next question comes from Mr. Ron Mills of Johnson Rice. Please go ahead.
Good morning, guys. Question as we try to compare slide five to slide seven in terms of your EURs per location. The core EURs of 1.2 million barrels, is that just the difference in the mix of the Wild Basin and the core to get to the 1.2 million barrels?
Yeah, that's correct. It's the Wild Basin EURs plus everything outside the core. If you combine the type curves that you see on page five and six, take a weighted average of that, you'd get to that 1.2.
Based at least on the early results in Wild Basin, it looks like there's obviously maybe even some upside versus the 25% you highlighted. 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. Yeah, we look at all the other operators' results in the basin. We're focused on everybody that's done these higher sand loadings both inside and outside the core. You're seeing some really good results. Based on that, like you said, there's 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, we're excited about the results we're seeing both in-house and what other guys are doing as well.
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 "core?
Yeah, that's really a big part of the play for us this year and next year, is as we test, just like you said, 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. Then two other quick ones. One on OMS, the increased spending, and the associated increased EBITDA. One of the other benefits there is, did your OMS system somewhat insulate you in the fourth quarter against some of the severe weather? Can that continue to provide some insulation relative to maybe some of your peers in tough weather conditions?
Yeah, absolutely. We've talked about this a lot, Ron. The less trucks, the better. Whether you're water, produced water, oil, fresh water for fracs, the more you can do across pipe and not on trucks. You get enough snow, and trucks can't move. The more we can do through pipe, the better.
Great. Then just so Michael doesn't get left out. On the differential guidance, the $3-$4 through the year, do you have any sense of how that may look through the year? Should it remain similar to the $4+ range in the early part, can start moving down in the back half to once you have the impact of DAPL, where do you think it gets to as you think for 2018 and beyond?
Yeah, I think you're exactly right there, Ron, that it is gonna start probably on the higher side of that range at the beginning of the year. We'll move towards the lower side when DAPL comes on, DAPL's called for line fill, 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. That should meaningfully tighten differentials. We're starting to see that happen even as they call for line fill already.
Perfect. Thank you, guys.
Thanks, Ron.
The next question comes from David Tameron of Wells Fargo. Please go ahead.
Morning.
Hey, Dave.
Michael, just before we leave DAPL, can you walk me through
$2-$3 range. As you know, anytime we see a pipeline start up, there's always a dynamic impact somewhere else that nobody ever appreciates until it's up and running. 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 through the entire basin? I'm just trying to think of some of the details as far as
Yeah
transfer points and
Sure. No, it's a good question. I think what will happen is, DAPL's a large system with numerous take points throughout the basin, so it's actually going to help differentials throughout the basin. 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. It's going to likely be pretty full as it comes online. Well, that production has to come from somewhere. You have a pipeline that's nearly half of 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's 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. Everybody's going to have to lower cost to try to get barrels onto wherever their dedications are. We think it's going to be an overall impact to the basin, not necessarily those that are just shipping on DAPL. It just provides a lot of competition for your barrels across the basin.
Okay. That's part of why I was going with that. You could be bidding some pretty low numbers just to get it on the base. Okay.
The good thing for us is we have very few of our barrels locked into long-term agreements. Part of the strategy of our marketing team was that we thought there would be more takeaway capacity than production in the basin. In that situation, we'd want to be more short-term oriented, and we think that's really playing out to our advantage.
Okay. Just back to the higher proppant jobs. 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 wouldn't work? What's the difference in the rock as far as the willingness to accept the higher frac or the more sand and the bigger frac? Can you just address that?
Yeah. We really don't 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. A lot of energy in that reservoir and really good oil charge. We've seen great uplift, but we expect to. We've already seen this with some third-party jobs, as you get outside of Wild Basin into other parts of the core, and seen similar things as you go into the extended core. The reservoir in general, as you go to the west, for example, 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. Taylor, with any change in the way you approach it from an artificial lift standpoint with the different completion jobs, thinking outside the core?
Yeah. You really have all the same options at your disposal. We've used a mix of artificial lift depending on where we are. Anything from gas lift, where we have a lot of concentrated completions in an area and a good gas supply. We use a lot of electric submersible pumps. ESPs and then larger beam pump units like Rotaflex that can move more fluid. You really have all of 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. We may use a bit more of ESPs in some of those areas that are a little more distal.
Okay, just specific to the completion jobs, if you use higher completion jobs in the extended core, you pull on the reservoir a little harder. Would that imply a sooner lift job, or am I overthinking that?
You mean in terms of conversion to artificial lift?
Yeah.
Yeah. 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. Wells are tending to flow longer. That John Drew well, the 20 million pounder in Wild Basin's a great example. It's nine months in, and it's still flowing at a nice pressure. We think we'll continue to see that in other areas. There's 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 wells. I think that'll play out as we do these bigger frac jobs, even outside the core.
Last one for me. Obviously realizing that, well, not obvious, but type curves in Netherland, Sewell, and D&M reserve bookings don't always match up, just given the conservative nature of the reserve firms. Can you talk about what they're allowing you to book right now in some of these I'm just thinking of 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 were tracking the one five. What are you guys booking on a per well for some of the new drills out there?
Keep in mind that our reserves, they're done by D&M, and they actually do an independent reserve report, so they're not auditing our results.
Yeah.
When you look at the way they book their wells in general, we have ups and downs, but generally, they're in line with what we've booked.
Okay. All right. Thanks. Thanks for all the color.
You bet. Thanks, Dave.
The next question comes from James Spicer of Wells Fargo. Please go ahead.
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 whatever other metrics you look at? 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. 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. From a debt-to-EBITDA standpoint, think about, we've always said that we'd like to get in a normalized oil price over time, back under two 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. 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.
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. 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 the balance sheet. 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 cash flow come in.
Okay, great. That's helpful. Secondly, obviously your infrastructure investments have been quite strategic, there's some good growth ahead, especially this year. Where do 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. The good thing is that the midstream capital that we spent last year, we spent overall on our capital budget, basically within cash flow. The next couple of years, we're going to be generating free cash flow. There's not as much of a need to monetize, but we are certainly looking at it. 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.
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. Having all of the, what I call the yeah, buts behind us is helpful in terms of valuation of the asset.
Yep. I understand. Thanks a lot.
The next question comes from John Nelson of Goldman Sachs. Please go ahead.
Good morning, thank you for taking my questions.
Hey, John.
I had a question on the higher intensity completions, specifically the 20 million pound well at Wild Basin that you guys have in your slides. I'm a finance guy, so I don't want to get too far out over my skis here, but is the well bounded on both sides? I guess what I'm trying to get at is to see if any of the outperformance is maybe stealing from potential offset locations, or is this purely how we should think about a repeatable well?
That particular well is a lease line well, so it's got wells tightly in our regular spacing on one side, spacing a little bit bigger on the other. We think it is going to be represented. Now that's a 20 million pound well. I think a good comparison point is a 10 million pound well. So when you look at the wells that we've done are 10 million pounds, those are more entrenched within all the regular spacing. 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. We think you're going to have good results.
Okay. That's really helpful for a poorly worded question. Just to be clear on the inventory changes, it looks just from eyeballing it, did Eastern Red Bank move into the core and 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 move, that's a good characterization.
Okay. 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?
Maybe a little bit high.
Yeah. A little bit under that, but you're in the right ballpark.
115, okay, perfect. Thanks. Congrats on the quarter, guys.
Thanks, John.
The next question comes from Joseph Allman of Citigroup. Go ahead.
Hi, good morning, everyone. This is Janine Stichter. I guess in terms of, you made some comments about trying to pull some of the extended core forward into the core category. I think you also mentioned that the additional rigs that you're adding will be split between Alger and Indian Hills. 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.
As Tommy mentioned, we're doing some of that early. We're fracking some wells up in Red Bank. We talked about it'll be April, May timeframe when we get on those wells. As we see results from that work, there's results from other operators we're looking at. We 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. That work will stretch out 2017 and into 2018. As we pull all 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. What other things are you changing in the new pilot?
Yeah, the main thing is going to be the increased stage count relative to what we've done historically, 50 stages, and then the higher sand loadings. It'll be going from the old wells that were four million pound frac jobs to 10s and up.
Okay. 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. I think you might have said before, and I'm not sure if I caught it, that you did include some risking, but not the full 25%. I just wanted to circle back to your thoughts on that.
Yeah. We've got some of the production baked in, but not the full 25%. That's exactly right.
Is it more like the 5%-10% range, or just too early to say?
It's above zero and less than 25.
Okay. We can work with that.
All right.
Thank you 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. Just as importantly, has put us in a great position going forward. Thanks again for being with us today.
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