Good morning, everyone. My name is Jamie, and I will be your conference operator today. At this time, I'd like to welcome everyone to the Q4 2017 earnings release and operations Update for Oasis Petroleum. All participants will be in a listen only mode. After today's presentation, there will be an opportunity to ask questions.
Questions. As you also know, today's event is being recorded. At this time, I'd like to turn the conference call over to Michael Liu, Oasis Petroleum CFO to begin the conference. Mr. Liu, you may begin.
Thank you, Jamie. Good morning, everyone. This is Michael Liu. Today, we are reporting our year end and Q4 2017 financial and operational results. We're delighted to have you on our call.
I'm joined today by Tommy Nusz and Taylor Reid as well as other members of the team. Please be advised that our remarks on both Oasis Petroleum and Oasis Midstream Partners 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 releases and conference calls. Those risks include, among others, matters that we've described in our earnings releases as well as in our filings with the Securities and Exchange Commission, including our annual report on Form 10 ks and our quarterly reports on Form 10 Q. We disclaim any obligation to update these forward looking statements.
During this conference call, we will make reference to non GAAP measures and reconciliations to the applicable GAAP measures can be found in our earnings releases and on our websites. 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 thank you for joining our call. 2017 was a tremendous year for Oasis including several milestone events capped off by a great Q4 and I'm very excited about the outlook over the next 24 months. We ended the year on a high note anchored by our tremendous cornerstone asset in the Williston Basin. We produced over 73,000 BOEs per day for the quarter and successfully executed on completion program that ended up being almost 3 times our Q1 of 2017 activity as we took advantage of some relatively mild weather pulling about 10 wells from 2018 into the end of 2017. The team did an exceptional job throughout the year, achieving significant milestones including the successful integration of our second frac spread, the realization of remarkably tight differentials with the startup of the Dakota Access Pipeline, which we have a direct tie into through Oasis Midstream Services.
We initiated construction of our Phase 2 gas plant we announced in November. We entered the Permian with our acquisition of approximately 22,000 net acres in the Delaware Basin and through a combination of that acquisition and the expansion of core footprint in the Williston, we more than doubled our core inventory that is resilient to very low oil prices and that will provide us with extremely competitive cash margins. Forge Delaware was a significant transaction for Oasis as we are now well positioned with significant inventory in the core of the 2 best U. S. Oil basins.
The acquisition further improves the long term capital efficiency of our development program and we look forward to continuing to demonstrate our executional strength as we ramp up activity in the Delaware. As we enter 2018, we've moved we've more than doubled our net core inventory versus this time last year. In addition to the Delaware acquisition, we've also expanded our Williston core footprint by moving our Painted Woods position into the core. We've always thought very highly of the rock quality in Painted Woods and many of our peers have completed some strong wells in and around that acreage over the past couple of years utilizing current completion designs. This has solidified our expectations on well recoveries and returns.
We will start doing work ourselves in Painted Woods this summer pilot testing stimulation design and spacing. You've heard us talk at length about our focus on capital discipline and capital efficiency, living within cash flow and managing business risk to generate strong full cycle returns. I know discussion around these topics has become the rage recently, but these values have been at the core of our management strategy for years. We were one of the first, if not the first mid cap E and Ps to be cash flow positive during the downturn and since we've grown production from 50,000 BOEs per day in 2015 to over 75,000 today while spending within cash flow at the E and P level. Going forward, we expect to continue to be E and P cash flow neutral to positive with 15% to 20% production growth through 2019 at a $55 to $60 oil price.
This is underpinned by 2 terrific assets Williston and Delaware that will drive high full cycle returns that should accrete to our shareholders. The team continues to work on cost structure while focusing on recoveries and optimizing completion design to drive improvements in well economics. We're focused on continuing to streamline operations with lower costs and we look forward to transferring that expertise to the Delaware Basin where we can use what we've learned in the Williston to attack some of the current challenges that operators are dealing with there. Our high quality oil weighted assets coupled with our efficient and vertically integrated operating structure drive peer leading cash margins for Oasis. Our single well returns in both the Williston and the Delaware are competitive with any basin in the country and our business development strategy is focused on multiplying that success through core bolt on acquisitions.
One of our differentiating factors as a company has been our ability to make accretive and opportunistic investments in the services and midstream sectors when we found ourselves in a dislocated market. Our first step in this direction was with OWS in 2012 and since we've realized 3 times our invested capital in that business. We recently expanded that business with the addition of a second frac spread and our frac efficiencies have been exceptional. OMS has also been a big success for us and continues to grow through internal expansion, a decent pipeline of 3rd party opportunities and new projects yielding attractive IRRs with build multiples of 4 to 5 times. In September of 2017, we completed the IPO of Oasis Midstream Partners or OMP and see a fantastic runway for that business in the coming years.
As you know, gas production continues to increase in the Williston and has the potential to outstrip processing capacity in the short term. Our team has done a great job being in front of that and had the foresight to initiate front end work on Phase 2 of our Wild Basin gas facility back in early 2017. Construction on our new 200,000,000 a day processing train started in mid-twenty 17 and is expected to be operational late this year. Oasis now has 2 core assets in the 2 best oil basins in the United States and on top of that, we have a significant and growing midstream business that is majority owned by the Oasis shareholders. Combining all this, we firmly believe Oasis is one of the best positioned companies in the sector and represents a uniquely attractive investment opportunity.
With that, I'll turn the call over to Taylor. Thanks, Tobey.
The team ended 2017 on a high and we're off to a great start in 2018 as well. This year, we expect to complete 100 to 110 operated wells in the Williston and 6 to 8 wells in the Permian with total company production averaging 80,000 to 83,000 barrels of oil equivalent per day for the year. We expect to accomplish that by spending $815,000,000 to $855,000,000 of E and P capital across both basins with about 85% of that capital in the Williston and about 90% of E and P capital on drilling and completions. That program should allow us to exit 2018 at about 83,000 barrels equivalent per day in the Williston and about 5,000 barrels equivalent in the Delaware for a total combined exit rate of about 88,000 barrels equivalent per day. For 2019, we expect to double production in the Delaware exiting at 10,000 barrels equivalent per day with the total company exit rate of 15% to 20% above 2018 exit.
Keep in mind that all of the volume totals are before the impact of our divestiture program. Consistent with our strategy since 2015, we expect to continue running the E and P business within cash flow. Minimal Delaware outspend should be more than offset by free cash flow generation from the Williston. In the Williston, we are excited to announce the movement of most of our Painted Woods acreage from extended core into core. This brings our total net core inventory to 585 net locations.
Combined with the extended core, Oasis now has over 1050 net locations with oil price breakevens below $45 WTI in the Williston alone. We continue to see further improved well performance from our core Williston acreage with our basin leading completion designs driving enhanced well performance. Our average well results continue to perform in line with expectations even in spacing density. We've updated our type curves to reflect well performance with the enhanced completions and within current spacing design. As previously discussed, our wells on pad development are generally constrained for the 1st 6 months or so.
In spite of that fact, they are producing more during this early period than previously modeled, so we've adjusted the type curve. The EURs have stayed about the same, but with this higher early production, well returns are higher as shown on Slide 11 in the presentation. Note that we have combined Alger and Wild Basin into one performance group. That's driven by well performance, but also by the reality that 4 of our 5 rigs are in those two areas currently. On the operational cost front, the team has continued to lower cost and use our flexible marketing program to drive basin leading differentials.
Our lease operating expenses per BOE have dropped by 35% since 2014. Our 4th quarter LOE was 6.42 dollars per BOE, which was one of the lowest ever for the company as we continue to realize some of the highest cash margins among Williston operators. We look forward to applying our operational successes and lessons learned to the Delaware where we expect to be able to drive down costs and optimize operations as well. Part of what continues to help us maintain top tier efficiency and drive down well cost are our OWS and third party frac crews. Our internal and third party crews have allowed us to maintain cost advantages, quality and availability of services and manage well cost inflation.
We currently have 2 internal frac crews working for us and 1 dedicated third party crew. Oasis has worked hard to develop strong relationships with our partners on the service side and we think that these relationships will translate to a smooth transition into the Delaware. Part of what allows us to enjoy such tight price differentials, low LOE and operational flexibility is our strategic investment in Oasis Midstream Services and our new MOP Oasis Midstream Partners, which provide gas gathering and processing, crude oil gathering and produce and freshwater services. This allows us to ensure lower operating cost and higher price realizations by providing surety of service and the ability to meet regulatory gas capture requirements and avoid production curtailment. We've been focused on the overall tight infrastructure in the basin for some time and have invested strategically to avoid bottlenecks.
We plan on continuing to invest in attractive midstream projects in 2018 with expected 4 to 5 times build multiples. We expect midstream investments at the OAS level to eventually be reimbursed by OMP in the form of drop downs from OAS to OMP. I would now like to shift focus to our Delaware assets. We are excited about the new position. As you can see from our maps, it is located in the deepest, oiliest part of the Delaware.
The asset is almost all operated and highly contiguous, allowing for us to drill long laterals on over 2 thirds of the acreage. We plan on further consolidating our position to small accretive bolt on acquisitions as well. Our Delaware acreage is also largely undedicated from a midstream standpoint, providing a potential attractive growth avenue for OMS and OMP. The team sees potential production from 6 primary and 4 secondary zones with over 600 gross locations in the primary targets and additional upside from the secondary zones. In terms of well performance, Oasis Wolfcamp wells continue to outperform the 1,200,000 BOE type curves used by industry in the area.
All wells are still naturally flowing even after 18 months of production. Low operating cost and further completion optimization give wells the ability to show impressive returns on par with our core Williston well performance. We're also excited about the potential on the Bone Springs interval. We have 2 tests, albeit in early time, that are in the Bone Springs Shale. There are also numerous competitor tests to the Bone Springs Shale and the sand in our area.
We'll continue to monitor results and give more color on performance in future calls. To close, our team has done an outstanding job of executing on our plan in the Williston and on identifying and closing on a great complementary asset in the Delaware. We're excited about moving both of these great assets forward as we move into 2018. With that, I'll now turn the call over to Mike.
Thanks, Taylor. On the financial front, we continue to enjoy strong liquidity levels with over $1,300,000,000 committed on our revolving credit facility and a total borrowing base of $1,600,000,000 Of that amount, only $70,000,000 was outstanding on December 31, 2017, giving a net debt to 4th quarter 2017 annualized EBITDA multiple of 2.3 times. We have no significant near term debt maturities and our borrowing base commitments recently increased by $200,000,000 We also funded the final $502,000,000 cash portion of the Forge Delaware acquisition upon closing in February using our revolver. In addition, OMP's revolver has a total capacity of $200,000,000 of which $78,000,000 was drawn as of year end. Our 2018 program is well secured given our prudent financial risk management with approximately 70% of our 2018 estimated production hedged and we are starting to layer in hedges for 2019.
Our strong hedging program ensures operational success at various commodity price levels. We continue to have pure leading cash margins, which were driven in the 4th quarter by some of the best realized prices in the company's history combined with lower operating costs from streamlined operations. This drove EBITDA of over $236,000,000 in the 4th quarter and over $707,000,000 on the year. We expect this success to continue in 2018 with differentials expected to be in the 1.50
dollars to $2 per barrel range,
LOE to be in the low to mid $7 range and marketing, transportation and gathering expenses per BOE to be in the $2.75 to $3 range. Tommy and Taylor both discussed our continued focus on capital discipline and returns. On Page 5 of our presentation, we show how we generated free cash flow in 2015 2016 including midstream capital spend. In 2017, we were able to fund midstream capital through our OMP IPO. This allowed us to direct E and P cash flow back into high rate of return E and P capital projects.
This resulted in 2017 free cash flow generation on the E and P business, while generating a 18% exit to exit growth. As we think about the business going forward, given access to Midstream Capital through OMP, we will continue to direct E and P capital to the E and P business, which drives the 15% to 20% growth over the coming years. Just as importantly, OMP has significant opportunities in front of them. OMP is one of few midstream providers out in front of the Williston Basin growth and is in great position to not only support Oasis' growth, but also third party operators in the basin. The 2018 Midstream capital spend is comprised of projects at a 4 to 5 times build multiple supported by Oasis' capital program, which also has significant incremental third party opportunities, which are not yet baked in.
This symbiotic relationship between the upstream and midstream companies will allow both companies to generate significant capital efficient growth for their respective share and unitholders. As we announced in December, we are in the early stages of a Williston divestiture program focused on portions of our Fairway and non op assets. In total, we expect asset sales to be at least $500,000,000 in 2018 targeting a midyear timeline. We have received significant inbounds on the process and remain confident in our ability to achieve expectations. Since it is active and ongoing process, there's not much more that we can say, but we'll update you on events once they materialize.
The impact of these sales on operational and financial results is not baked into our 2018 plan and we'll adjust guidance accordingly when the transaction is announced. As we close out 2017, we want to congratulate our team on its continued focus on capital discipline, generating pure leading cash margins and delivering strong returns for our shareholders. With that said, I'll turn the call over to Jamie for questions.
And our first question today comes from Brad Heffern from RBC Capital Markets. Please go ahead with your question.
Hey, good morning, everyone.
Good morning.
On the midstream CapEx front, obviously Oasis is funding or OAS is funding a lot of the capital here in 2018. How do you think about the timeline for drops and when OAS will potentially get reimbursed for that? And then if you're building out at a 4 to 5 times multiple, is OAS going to see the upside in terms of drop multiples from building that out or how do you think about that?
Yes. So, we don't have perfect visibility into timing. Obviously, there is some things in terms of access to markets, etcetera, but we do expect that, call it over a 12 month to 18 month timeframe, you're going to fund that midstream capital through either at the OMP level or through drop downs. In terms of multiples, we'll have to decide kind of at that time where those multiples are in terms of drop multiples. We obviously can't disclose on that right now.
Okay. Got it. I think
there'll be adequate benefit for both companies though. I think it can be a positive for both sides.
Okay. And can you give your updated thoughts on current service cost trends and what the sort of leading edge well costs are in the Bakken right now?
So the what we've seen in terms of well costs in 2017 first half of the year had a fair ramp and then kind of flattened out as we got into the second half of the year. We really haven't seen and this is most focused on Williston at this point because that's where the lion's share of the activity is. The well costs from 2017 coming into 2018 have really remained flat and the cost for our £10,000,000 slickwater job is $7,700,000
Okay. Thanks all.
Thanks.
Our next question comes from Drew Venker from Morgan Stanley. Please go ahead with your question.
Yes, I was hoping and you may from your prepared remarks, you didn't not be able to say a whole lot, but you can talk about how you might want to position the asset sales and different pieces or it's completely open ended at this point?
Yes, Drew, there's not a whole lot more that we can say on that side. I will note that in terms of you look at our Fairway acreage and our non op assets, we have, we think significantly more asset value than the 500 that we're talking about. So, as you mentioned, it can take a couple of different turns and we're going to we've had a lot of interest and we'll give you guys more of an update as we move along.
Okay. And on the Delaware, as you guys go throughout the year, should we be expecting completion pace to be back and weighted? And then you guys talked about potentially adding a rig later in 2018 beyond your initial plan. How should we think about your latest thoughts there on what makes sense for activity levels?
Yes, it's a good question. We're planning on, as we've talked about, 1 to 2 rigs. We get the 1 rig running right now and a second rig in mid year. In terms of completion activity, 6 to 8 wells, but we'll drill quite a few more wells during the year. So, we're projecting kind of 16 wells to 18 wells drilled.
So, we're going to lag a bit on completion pace. Some of that's driven by adding that second rig in the last half of the year and some of it is driven by getting to the point where we have a dedicated frac crew. We just don't have enough activity yet. So, it's going to be a little lumpier until we get that dedicated frack crew. And the reason we don't have it, we just don't have enough wells to justify dedicated frackers, not that we couldn't get one.
When we get to kind of 2 to 3 rigs and we'll have enough activity where we'll have a dedicated crew.
Okay. So it's likely not until probably early 2019, where you'd be having a dedicated crew? Yes. Okay. And then is there a follow-up to that.
Is there much non op activity that you'd expect on that position that maybe has some impact on your decision whether to add that second rig or not, so you don't exceed your budget?
Yes, the second rig is baked into the budget, but there is a lot of activity around us. We baked in some non op activity as well. We don't think that participation in 3rd party wells is going to push us over so that we can't pick up that rig. We don't think that'll be a problem.
Okay. And is there any reason to delay that addition of the rig or not go quite as fast as soon, because you want to see as many offsetting results as possible? Or I mean, just to talk about a lot of well control around you. Just curious how you think about that and how it plays into your plans?
Yes. That's a great point. The we've intentionally kind of kept the pace so that we're not out drilling our knowledge. We want to really make sure that we understand the subsurface before we go into really full development like we've done in the Williston. This is a lot like some of the other projects we've done up there.
Wild Basin is a great example, where we're going
to go
in, have enough activity to understand the performance of all the intervals. And once we've got individual well performance in all the individuals, we'll be doing some small spacing test. And once we've got all that under our belt, then we'll really pick up the activity. And so that would be beyond a tube rig program out in kind of 2019 2020 timeframe. But to your point, definitely want to be careful that we don't outpace our knowledge.
Okay. And can you
just remind us on the drilling obligations, what how much is held or how much activity you need and when you might have material expirations if let's say you had and this is a hypothetical, but no activity for a period of time?
Yes. Our drilling obligations are pretty reasonable. We did the peak period, which is out in 2020 beyond, it requires 2 to 3 rigs to hold land.
Question comes from David Deckelbaum from KeyBanc. Please go ahead with your question.
Hey, guys. Good morning.
Good morning.
Just the core inventory move, including locations in Painted Woods, just interested how you're looking at potential inclusion of Red Bank or North Cottonwood with some of the other third party results. What your observations have been so far and what we might expect this year? So,
yes, we obviously made the move with Painted Woods. And if you'll remember, actually, last year, we took part of Southeast Red Bank and moved that into the core based on the results. And if you look in the map on Page 11, you can see the red stars that show some of the competitor activity with enhanced completions. And based on the results that we had seen, you can see there's quite a few tests as you go west around Painted Woods based on that activity and then based on the quality of the results in our older style completions and the uplift that we've seen as you go to enhanced completions, we're comfortable that this is going to perform in the core. You can also see that we've got some pilots and there's one in particular in Red Bank as you go further to the west.
And there's not as many of these bigger completions. You can see there's just not any of those red stars around that part of Red Bank. So, when we get those pilots that we're going to drill this year on and tested, that will give us information to make that determination on whether we move additional Red Bank into the quarter. And then Cottonwood, there's really just one a handful. There's one in particular that we're focused on a 3 mile laterals in Cottonwood, but a couple other tests that are earlier time that are a little bigger stimulation that will give us that information.
But that's all really early time. We're encouraged by what we're seeing, but not just enough data yet.
I appreciate that. And then if I kind of ask on the updated type curves, it looks like the accelerated 1st year cums are about 20% to 25% higher than that base or prior type curve. And I guess the total EURs looks like about 1% lower. Are you seeing that on wells that have been online beyond the year? And are you seeing that in the 2nd year decline?
Or is this happening much later in the life of the well and sort of the economic life is being shortened now?
Yes. So the what we're seeing is you're talking about that early time period real outperformance and the areas where we have additional data, we don't have a lot more with the high intensity completions, a ton more data, but we do have some that go out beyond 400 and they continue to outperform. We think that over time, you're likely to see the performance come back down. As you mentioned, the old type curves and the new type curves are about the same, slightly less with the new type curves. So out in time or in the tail, you're going to see a crossover.
But the good news is you've got all this production been pulled forward. And if you look at the table on the bottom right hand side of the page, you can see that the higher the returns on the new type curve wells are substantially above the old ones. So, like I said, eventually, you're going to see the performance drop off in the tail, but you're having better economic results as a result of that shape.
Hey, David, one other thing I'd mention is What year
I guess is that yes, sorry, go ahead.
Just one other thing is to note that is the population of the wells in those type curves are a little bit different as well. The old type curve on the left side of the page was Wild Basin only and now it's Wild Basin and Alger. And on the right side of the page, we've taken Alger out of that population and added in Painted Woods. And so there is a bit of a change in the population mix as well as
you think about those type curves.
I appreciate that, Michael. Thank you. I was just curious like I guess in your internal model now on your type curve because you display the 1st year, At what point does the cumulative production sort of converge to the old type curve? Is it year 3 or is it year 2?
It's going to be further out than that. You can see here we've got you already got 400 days. And so if you look at the same cume producing day type curve, you remain above it for really an extended period. It's going to be, yes, 5 years or more out from what you're seeing from the start here. So it's quite a ways out.
Yes. Okay. I appreciate that guys. Thank you.
You bet. Thanks, Dave.
Next question comes from Ron Mills from Johnson Rice. Please go ahead with your question.
Good morning. Just one follow-up on what they were just asking about. Once you start to cross over, given all that incremental value and production pulled forward, is there anything you're seeing in the existing wells that would suggest that after year 5 that you would have that strong of a rollover relative to the old curve?
It's not going to be like a sudden inflection point. It's going to be a gradual role in production. So, just like what you're seeing, it's going to take 5 years to for those curves that converge, it's going to be an extended period where they're not substantially apart.
Okay, great. As it moves to the Permian, you talked about and you have a graph showing the well performance exceeding the 1,200,000 barrel type curve. A couple of comments, I just want to make sure I understand. You talked about wells your wells still remaining on natural flow? And I'm assuming those are the wells drilled by forge.
And you also mentioned that your that performance is being achieved despite having somewhere in the £1600 of profit versus it looks like the type curve is at £2,000 Am I reading the information correct? And what do you think is driving some of that early performance?
So, Forage elected to really take a little more conservative approach to the stimulation. And so they're in general their stimulations have had a little lower profit loading than a number of the competitors in the area. And so that is an area, Ron, where we're excited about testing some bigger proppant loadings. And good case in point, we just recently completed a Bone Spring Shale well that we bumped up the loadings to more like £3,000 a foot, which you've seen a number of operators do in the area. So we'll be testing bigger loadings, also testing cluster spacing, number of stages, diverters, a lot of the things that we've been working with in Williston and things that we've seen other operators use around the position.
So, the great news is you got these wells that they've completed with the 1600 pound loadings or less than 2,000 pound loadings on average And they're outperforming the type curve for a 1,200,000 barrel equivalent well. We've just used an industry well at this point because we want to gather enough data before we put out our curve and we'll do that in future quarters.
And because of that outperformance, I mean, even after 60 days on those wells, I mean, you're looking at looks like plus or minus 50% on a cume basis. Is that a function of just the concentration of your rock as you outlined and being some of the deepest and higher pressured parts of the basin?
Yes. As we've talked about this position, deep, over pressured, very oily, 80 plus percent oil cuts and those things are we think are translating to really some outstanding performance. So we'll as we apply some of these bigger jobs, we'll be interested to see how they perform.
Okay, great. And I know you pulled some 2018 completions into the latter part of 2017. What should we think about the timing of those planned completions for this year, the 100 to 110 in the Bakken and the 6 to 8 in the Delaware?
It's likely to be as you've seen in past years, because of winter, you're likely to see the Q1 be a little more muted in terms of activity. The good news is that because of that acceleration at year end, even with a little lighter activity in the Q1, we're going to we're projecting to grow production slightly. And so that sets us up well as we go into 2Q and 3Q. So, cold, it's been a cold start to the year certainly in late December early January. We've got breakup ahead of us, which normal kind of April timeframe, we'll see what breakup looks like.
But if you took that 100 wells and instead of being 25, if it was evenly spread in the Q1, maybe you're 5,000,000 or 10,000,000 below that depending on where we end up and the rest of the stuff kind of gets spread out through the year. Okay.
And then one just clarification, Michael. Have you talked about the whether it be the acreage and or the production level associated with the fairway and non op positions that you may look to divest?
No, I don't think we've totally characterized that Ron, but if you look at kind of fairway and non op, you can think about in total, there is probably 8,000 barrels a day and 200,000 some odd acres. But once again, I don't think you need to sell all that to get to our numbers.
That's why I was getting that. I don't I was trying to get a sense. It doesn't seem like you have to sell the whole position to get there. I just didn't know if we had those metrics. Exactly.
I'll let someone else jump on. Thank you. Thanks. Thanks, Ron.
And our next question comes from Jeffrey Lamberjohn from TPH. Please go ahead with your question.
Good morning. Thanks for taking my questions.
Good morning, Jeff.
Just first one on the targeted growth rate. Should we think about the 15% 20% that you've talked about for 2019 as kind of a good run rate as you look beyond that? And then for 2019 and for any years in which you target that similar growth level, will you target the same coverage from an engine standpoint?
Yes. We're given kind of the 2 years of guidance, but we did it last year and given our projections and the way we're looking at things over the next couple of years, we think we can continue that growth trajectory. And what I'll say is that having OMP around to fund the midstream side of it allows us to put capital back to work. We think very strong capital efficiency metrics. You look at most of our activity is going to be in that Wild Basin Alger areas over the year and those wells are call 1 year cash paybacks.
So they're pretty strong kind of recycling cash at a very fast rate. So very strong projects on the E and P side. We think the Permian or the Delaware asset will be just as strong going forward. So we have a very deep inventory that allows that E and P side to grow naturally going forward. So, we feel very positive on that side of things.
And then on the hedging side, you asked about hedging levels and historically we've hedged kind of in that, call it 60 ish percent by the end of the year and I expect that and we've been very kind of systematic and we layer into that hedge kind of that throughout the year before and we'll kind of continue that practice for now. It gives us a lot of certainty on our program going forward. And so, we'll likely kind of continue that practice.
I appreciate that. And then as you think about asset sale proceeds coming later in the year, should we assume that a large chunk of that's going towards plugging the midstream spend for 2018? And how do you think about the excess or if commodity prices allow for excess cash flow and just prioritizing that? Would that be dedicated to testing more Williston acreage? It's kind of an extended core bucket, accelerating the delineation of the Delaware, infrastructure build out, shareholder returns, how do you think about that ranking?
Yes. I think it can be a combination of any of the above. And what you didn't mention was kind of the easiest, which is just reducing leverage, right? And so that's where we kind of have it earmarked right now and we'll continue to watch and see as those proceeds come in where we allocate that. But the one thing that I'd say probably not is on the midstream side.
We do kind of see that as using that OMP, the midstream or the MLP vehicle as a way to incorporate that spend. So the asset sales are more for the upstream side of the business.
Thank you.
And our next question comes from Paul Grigel from Macquarie. Please go ahead with your question.
Hi, good morning. I guess focusing on the Delaware side, kind of 2 part on the completion side. 1, do you see there's any risk either on the cost front or the logistics front in using spot crews down there right now? And what would be the desire to bring in what would potentially either be the 2nd frac spread moving down or build a new third spread and put it into the Delaware over time, especially given the rig requirement you mentioned in 2020?
You bet. We don't we haven't seen a problem with getting the spot crews at this point. We've talked with a lot of providers, a number of them that we've used up in the Williston and that those relationships we think are going to help us out. But we don't perceive a problem getting frac crews. You like to ultimately get in a position where you've got a steady program and using a dedicated crew because you just get so much more efficiency and cost benefit out of that activity where you're using the same group on all your wells and they're not going off and doing work for other people.
In terms of do we bring a crew down or build a crew to service the Delaware? That's a decision we'll make as we get closer to the point that we can justify a dedicated crew. We're really open to either. I mean, we want to make the best decision from profitability and cost standpoint to the company. And if that investment is justified, then we'll go down that path.
You've seen us do it before in the Williston and we'll entertain it here, but I've not made a decision either way.
Okay. And then I guess a follow-up question on the incentive. You guys note that the compensation metrics are aligned to the key inputs of corporate returns. Has there been a discussion on changing that to be explicitly focused on corporate return and on per share metrics as we kind of head into the proxy filing here?
I wouldn't expect to see anything this year. I mean, it's a little bit late for that. But as you mentioned and as we talked about it, we try to measure the things that ultimately will translate into returns and something that the organization can relate to in their daily activities and to maintain alignment. But it is something that we're looking at on a go forward basis.
A lot of people look a lot of people doing the
same work. And so we'll also monitor what other people are doing and how they're communicating it. But it's ultimately it's got to be we've got to come up with a system that helps the organization align to ultimate performance.
And just for clarity that would be on the 2019 program that you'd be looking to make those changes since it's usually in arrears?
Well, yes. Well, yes, basically, I mean, our targets organizational targets and metrics are with our Board are already set for 2018. So obviously because of that it would be 2019 at the earliest.
Okay. Just wanted to clarify. Thank you. Yes.
You bet. Yes.
Our next question comes from Nitin Kumar from Deutsche Bank. Please go ahead with your question.
Good morning, guys, and thank you for taking my questions. The first question is on the Delaware. I might have missed this, did you talk about the AFEs that you're seeing there right now? And then specifically, you mentioned 16 to 18 DUCs by the end of the year. Could you speak to the makeup of that program?
What zones, laterals, etcetera, you might be trying with those DUCs? Okay.
So, first in terms of AFEs, it just depends on the operator, what they're doing, size of stimulation and exactly where the well is. At this point, we're kind of in the 11 to 11.5 range and still working on what the wells are going to look like. We're actually closed on Valentine's Day. So, we've now officially owned the asset, but we're in a transition period with Ford to the prior operator and we'll take full control of the assets and as we work through the year, we'll be moving to bring the cost down. So early days on the cost side of the business, We're excited about some of the things we can do from an optimization standpoint on the drilling and completion side.
So we'll give you more color on that in the future quarters. And then in terms of the 2016 to 18 wells I was talking about, we'll drill 16 to 18 and then complete 6 to 8 wells. So you'll have around 10 DUCs that will carry out of the year as we go. In terms of flavor of the intervals that we'll be testing, it'll be like we've done so far Wolfcamp and Bone Springs wells focus being on acreage holding, testing intervals across the position and then also doing some small pilot spacing test.
Got you. And then just in terms of the midstream, it seems like the $230,000,000 to $270,000,000 is dedicated towards the Bakken. When do you expect to start spending on midstream for the Delaware? And how should we think about funding that?
Yes, we are working the midstream side. On the Delaware side, there are a lot of options out there, both internal options as well as 3rd party options. So we're looking kind of through all the commodities, whether it's oil, gas or water, what the best options are there. If they are to be done internally, I think you can you would see that that'd be a big opportunity for the partnership to be involved with. So, I think that's how you can think about that.
Great. Thanks guys.
Thank you.
Our next question comes from John Osenbeck from Seaport Global. Please go ahead with your question.
Good morning. Thanks for taking my question. A follow-up regarding your updated inventory estimates in the Bakken. I was wondering how that affects your outlook for terminal activities that activity levels there? I understand growth near term is more likely to come from the Delaware, but longer term, do you envision a higher level of activity in the Bakken in the out years just given your increased inventory?
Yes. So, it's a good question. And just to kind of orient, if you look at the activity levels on the Bakken up in the Bakken and the Williston And if you think about the growth that we've been exhibiting, so exit to exit is I think Michael talked about in his comments was around 18%.
And
just in the Williston was around 16%. And so that's all within cash flow. And if you look at the increase in core inventory, we think that bodes well. You're going to continue to be able to substantially grow production and spend within cash flow in the Williston. And then when you roll this asset on top in the Delaware, it's just going to give you more growth on top of what we've been doing in the Williston.
So we expect to continue to maintain that kind of growth profile we've been seeing in the Williston, It's been within cash flow and then really add to that down in the Delaware.
Okay, got it. Appreciate it. Then I had a follow-up on the Three Forks and I apologize if I missed this, but is there any update to type curves from that formation? I noticed just sticking with the legacy £4,000,000 drop in 2018. So is it just fair to stick with the legacy type curves there?
Yes. We didn't put any updated 3 fourths type curves in our information. Keep in mind, one of the things as you look at the program going forward, it's more Bakken weighted. And so, thought it was important to focus on these Bakken wells and discuss the new shape of the curves like we've talked about.
Okay, great. And I guess just a point of clarification for me, I assume that it's not really going to be a co development between the Bakken and the Three Forks going forward. Is that the point you're trying to make there?
No. We actually continue to have co development in the Bakken and the Three Forks in some areas. But as you get out side of, for example, the place where we're most focused on continuing to do that is in Wild Basin and Alger. As you work further to the West, we're beginning to move to more of a Bakken program. The inventory is about the same, but focusing the drilling on the Bakken.
And so as you get into Indian Hills and then into Painted Woods and even into Red Bank, more of that activity becomes Bakken dominated. And we're able to do that because the section as you go to the west generally thins And with the fracs that we're doing, these big high intensity fracs, we think we're draining the whole section with the wells in the Bakken. We're getting better economics with those wells and as a result, concentrating that activity in the Bakken and draining the Three Forks from above.
Okay, great. Appreciate the color. Last one for me really. Just looking at your remaining core and extended core inventory count, what's the ballpark split between the Bakken and the Three Forks?
In
the you're going to have to give us just a second. In the extended core, it's really all Bakken at this point. There's very limited Three Forks. In the core, it's about 70% Bakken.
Okay, great. Appreciate the color. That's it for me. Thanks.
Our next question comes from Phillips Johnston from Capital One. Please go ahead with your question.
Hey, guys. Thanks. Just one housekeeping question on the new type curves for the Bakken. I think in the past you've assumed a B factor of 1.6% and a terminal decline rate of 6%. I assume the B factor is lower and the terminal decline rate is higher, but I'm wondering if you're able
to provide any specifics on those?
Yes. So, the B factor is a little bit lower. So, we went from a 1.6 to now about a 1.4. Terminal decline didn't change. Okay.
And then the 2,500 GUR for the Wild Basin, is that the same still?
It's not that different early time.
Yes, it ultimately goes up a little bit. But to Michael's point early time, it's the same. Later in time, it's a little bit higher, more around 3,000.
Okay, perfect. Thanks guys.
And our next question comes from Dan McSpirit from BMO. Please go ahead with your question.
Folks, good morning. What is
the PDP decline rate on the oil and gas streams today in the Williston Basin?
So the PDP decline, we over the downturn, we really slowed activity down. We were in the kind of in the low 30s and around got down to around 30 as we got down to 2 rigs and had less activity as we ramped activity back up here. That decline has steepened a bit. So, now it's more in the 35% to 40% range. And that would be for 2018.
Okay. Very good. Thank you. And what spacing assumptions were used in the Delaware Basin to underwrite the acquisition? And how might those change over time?
And what impact if any could it have on inventory up or down?
Yes. So the spacing assumptions, we think we're pretty conservative, but generally it's in an interval, it's 6 wells, yes, per bench for each interval. And you can look on page 18 and it lists number of wells per interval. And then we're actually looking at lighter spacing for wells in the Third Bone Spring. But Page 18 has a good summary of that.
Very good. Thank you. Have a great day.
Thanks, Dan.
Our next question is from David Deckelbaum from KeyBanc. Please go ahead with your question.
I just had a quick follow-up guys. Michael, I think you said the indications have been really strong on the fairway sales. I know that you guys came up with sort of an internal target of $500,000,000 that maybe was somewhat arbitrary. And given the improvement in the inventory, would you guys be willing to part with the entire fairway if the appetite was there?
Yes. I think it's a little bit early to make that call. I think we threw more in the bucket than what we needed to hit the target. And there's a lot of interest, but then there's also
as Taylor talked about, there's a
lot of activity in whether it's improved completions or 3 mile laterals. And so we'll kind of feel our way through it. It'll be a moving target, but we're targeting 500. There's more than that in the bucket and we'll just have to see how that plays out.
Thanks guys.
Thanks, Dave.
And ladies and gentlemen, at this time, we've reached the end of today's question and answer session. I'd like to turn the conference call back over to Tommy Nusz for any closing remarks.
Thank you again for joining our call. The quality of our people and our assets combined with our focus on shareholder returns and capital discipline set us up for a great 2018 program and we're already off to a great start. Thanks again for joining us.
Ladies and gentlemen, that does conclude today's conference call. We do thank you for attending today's presentation. You may now disconnect your lines.