Oasis Petroleum Inc.
Q4 2017 Earnings Call Transcript

Published: 28 Feb 2018

[Operator:]

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 Fourth Quarter 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. Please also note today's event is being recorded. At this time, I'd like to turn the conference call over to Michael Lou, Oasis Petroleum's CFO, to begin the conference. Mr. Lou, you may begin.

[Michael H. Lou:]

Thank you, Jamie. Good morning, everyone. This is Michael Lou. Today, we are reporting our year-end and fourth quarter 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 have described in our earnings releases 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 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.

[Thomas B. Nusz:]

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 fourth quarter. 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 three times our first quarter 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-in to 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 our 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're now well-positioned with significant inventory in the core of the two 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 entered 2018, 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&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 Boes today, while spending within cash flow at the E&P level. Going forward, we expect to continue to be E&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 two 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 three 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 third-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-million-a-day processing train started in mid-2017 and is expected to be operational late this year. Oasis now has two core assets in the two 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.

[Taylor L. Reid:]

Thanks, Tommy. 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 million to $855 million of E&P capital across both basins, with about 85% of that capital in the Williston and about 90% of E&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&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 1,050 net locations with oil price break-evens 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 first six 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. 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 had combined Alger and Wild Basin into one performance group. That's driven by well performance, but also by the reality that four of our five 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 fourth quarter LOE was $6.42 per Boe. 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 two internal frac crews working for us and one 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 into a smooth transition into the Delaware. Part of what allows us to enjoy such tight price differentials, low LOE and operational flexibilities are strategic investment in Oasis Midstream Services and our new MLP Oasis Midstream Partners, which provide gas gathering and processing, crude oil gathering, and producing fresh water 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 the 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 dropdowns from OAS to OMP. I would now like to shift focus to our Delaware assets. We're 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 two-thirds of the acreage. We plan on further consolidating our position through small accretive bolt-on acquisitions as well. Our Delaware acreage is also largely and dedicated from a midstream standpoint, providing a potential attractive growth avenue for OMS and OMP. Our team sees potential production from six primary and four 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 continued to outperform the 1.2 million 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 the core Williston well performance. We're also excited about the potential on the Bone Spring's interval. We have two tests, albeit in early time, that are in the Bone Spring shale. There are also numerous competitor tests to the Bone Spring 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 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 Michael.

[Michael H. Lou:]

Thanks, Taylor. On the financial front, we continued to enjoy strong liquidity levels with over $1.3 billion committed on our revolving credit facility and a total borrowing base of $1.6 billion. Of that amount, only $70 million was outstanding on December 31, 2017, giving a net debt to fourth 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 million. We also funded the final $502 million 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 million, of which $78 million 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 peer-leading cash margins, which were driven in the fourth 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 million in the fourth quarter and over $707 million on the year. We expect this success to continue in 2018 with differentials expected to be in the $1.50 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 and 2016, including midstream capital spend. In 2017, we were able to fund midstream capital through our OMP IPO. This allowed us to direct E&P cash flow back into high rate of return E&P capital projects. This resulted in 2017 free cash flow generation on the E&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&P capital to the E&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-time 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 unit-holders. 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 million in 2018, targeting a mid-year 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 the 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 peer-leading cash margins, and delivering strong returns for our shareholders. With that said, I'll turn the call over to Jamie for questions.

[Operator:]

And our first question today comes from Brad Heffern from RBC Capital Markets. Please go ahead with your question.

[Brad Heffern:]

Hey. Good morning, everyone.

[Thomas B. Nusz:]

Morning.

[Brad Heffern:]

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 exceed the upside in terms of drop multiples from building that out or how do you think about that?

[Michael H. Lou:]

Yeah. So we don't have a perfect visibility into the timing. Obviously, there's some things in terms of access to markets, et cetera. But we do expect that, call it, over a 12- to 18-month timeframe, you're going to fund that midstream capital through either at the OMP level or through dropdowns. 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.

[Brad Heffern:]

Okay. Got it.

[Michael H. Lou:]

I think there'll be adequate benefit for both companies though. I think it can be a positive for both sides.

[Brad Heffern:]

Okay. And can you give your updated thoughts on current service cost trends and what the sort of leading edge well costs are on the Bakken right now?

[Taylor L. Reid:]

So what we've seen in terms of well cost 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 cost from 2017 coming into 2018, it really remained flat and the cost for our 10 million pound slickwater job is $7.7 million.

[Brad Heffern:]

Okay. Thanks, all.

[Thomas B. Nusz:]

Thanks.

[Operator:]

Our next question comes from Drew Venker from Morgan Stanley. Please go ahead with your question.

[Drew Venker:]

I was hoping, and you maybe from your prepared remarks, you may not be able to say a whole lot, but you can talk about how you might want to position the asset sales, if it's different pieces or it's completely open end at this point.

[Michael H. Lou:]

Yeah. Drew, there's not a whole lot more we can say on that side. I will note that, in terms of – if you look at our fairway acreage and our non-op assets, we have we think significantly more asset value than the $500 million that we're talking about. So, as you mentioned, it can take a couple of different turns, and we've had a lot of interest, and we'll give you guys more of an update as we move along.

[Drew Venker:]

Okay. And on the Delaware, as you guys go throughout the year, should we be expecting completion pace to be back-end-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?

[Taylor L. Reid:]

Yeah. It's a good question. We're planning on, as we've talked about, one to two rigs. We get the one rig running right now. Add a second rig in mid-year. In terms of completion activity, six to eight wells, but we'll drill quite a few more wells during the year. So we're projecting kind of 16 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 frac crew.

[Drew Venker:]

And then...

[Taylor L. Reid:]

And the reason we don't have it, we just don't have enough wells to justify a dedicated frac crew. It's not that we couldn't get one. When we get to kind of two to three rigs, then we'll have enough activity where we'll have a dedicated crew.

[Drew Venker:]

Okay. So it's likely not until probably early 2019...

[Taylor L. Reid:]

Yeah.

[Drew Venker:]

...where you'd be having a dedicated crew.

[Taylor L. Reid:]

Yeah.

[Drew Venker:]

Okay. And then, as 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?

[Taylor L. Reid:]

Yeah. The second rig's 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 third-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.

[Drew Venker:]

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? I guess you did talk about a lot of well control around you. Just curious how you think about that and how it plays into your plans.

[Taylor L. Reid:]

Yeah. That's a great point. We've intentionally kind of kept the pace so that we're not outdrilling 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's a great example. 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 also 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 two-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.

[Drew Venker:]

Okay. And can you just remind us on the drilling obligations, 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 hypothetical, but no activity for a period of time?

[Taylor L. Reid:]

Yeah. So our drilling obligations are pretty reasonable. When we get to the peak period, which is out in 2020 and beyond, it requires two to three rigs to hold land.

[Drew Venker:]

Okay. Thanks for the color.

[Taylor L. Reid:]

Thanks.

[Operator:]

And our next question comes from David Deckelbaum from KeyBanc. Please go ahead with your question.

[David A. Deckelbaum:]

Hey, guys. Good morning.

[Taylor L. Reid:]

Morning.

[David A. Deckelbaum:]

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.

[Taylor L. Reid:]

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 if 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 core. And then Cottonwood, there's really just a handful. There's one in particular that we're focused on, a 3-mile lateral over 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.

[David A. Deckelbaum:]

I appreciate that. And then, if I kind of ask, on the updated type curves, looks like the accelerated first year cumes 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 on line beyond the year? And are you seeing that in the second year decline? Or is this happening much later in the life of the well and sort of the economic life is being shortened now?

[Taylor L. Reid:]

Yeah. So 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 these high-intensity completions, a ton more data, but we do have some that go out beyond 400 days, 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 more in the tail, you're going to see a crossover. But the good news is you've got all this production that's been pulled forward. And if you look at the table, on the bottom right-hand side of the page, you can see that the returns on the new type curve wells were substantially above the old ones. So, like I said, eventually you're going to see the performance drop off in the tail, but you have a better economic result as a result of that shape.

[Michael H. Lou:]

Hey, David. One other thing I'd mention is...

[David A. Deckelbaum:]

In what year, I guess, is the – yeah, sorry. Go ahead.

[Michael H. Lou:]

David, just one other thing is to note that 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.

[David A. Deckelbaum:]

I appreciate that, Michael. Thank you. I was just curious, like, I guess in your internal model now on your type curve because you displayed the first year. At what point does the cumulative production sort of converge to the old type curve? Is it year three or is it year two?

[Taylor L. Reid:]

It's going to be further out than that. You can see here, 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. This is going to be, yes, five years or more out from what you're seeing from the start here. So it's quite a ways out.

[David A. Deckelbaum:]

Yeah. Okay. I appreciate that, guys. Thank you.

[Taylor L. Reid:]

Yeah.

[Thomas B. Nusz:]

You bet. Thanks, David.

[Operator:]

Our next question comes from Ron Mills from Johnson Rice. Please go ahead with your question.

[Ronald E. Mills:]

Yeah. Good morning. Just one follow-up...

[Thomas B. Nusz:]

Hey, Ron.

[Ronald E. Mills:]

...on what David was just asking about. Once you start to crossover, 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 five, that you would have that, that strong of a rollover relative to the old curve?

[Taylor L. Reid:]

It's not going to be like a sudden inflection point. It's going to be a gradual roll in production. So, just like what you're seeing, it's going to take five years for those curves to converge. It's going to be an extended period where they're not substantially apart.

[Ronald E. Mills:]

Okay. Great. As it moves to the Permian, you talked about – and you have graphs showing the well performance exceeding the 1.2-million-barrel type curve. A couple of comments. I just want to make sure I understand. You talked about your wells still remaining on natural flow. And I'm assuming those are the wells drilled by Forge. And you also mentioned that that performance is being achieved despite having somewhere in the 1,600 pounds of proppant versus it looks like the type curve is at 2,000 pounds. Am I reading the information correct and what do you think is driving some of that early performance?

[Taylor L. Reid:]

So, Forge elected to really take a little more conservative approach to the stimulation. And so, in general, their stimulations have had a little lower proppant 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 a good case in point, we've just recently completed a Bone Spring shale well that we bumped up the loadings to more like 3,000 pounds 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, a 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 that position. So the great news is you got these wells that they've completed with the 1,600-pound loadings or less than 2,000-pound loadings on average. And they're outperforming the type curve for a 1.2-million 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.

[Ronald E. Mills:]

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 in being some of the deepest and higher pressured parts of the basin?

[Taylor L. Reid:]

Yeah. As we've talked about, this position, deep, over pressured, very oily, 80-plus-percent oil cuts, and those things we think are translating to really some outstanding performance. So, as we apply some of these bigger jobs, it'll be interesting to see how they perform.

[Ronald E. Mills:]

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 wells in the Bakken and the 6 to 8 wells in the Delaware?

[Taylor L. Reid:]

It's likely to be – so, as you've seen in past years, because of winter, you're likely to see the first quarter 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 wider activity in the first quarter, we're projecting to grow production slightly. And so, that sets us up well as we go into 2Q and 3Q. So, it's been a cold start to the year certainly in late December and early January. We've got breakup ahead of us, which normal kind of that April timeframe we'll see what breakup looks like. But if you took that 100 wells, and instead of being 25 wells, if it was evenly spread in the first quarter, maybe you're 5 or 10 wells below that depending on where we end up, and the rest of the stuff kind of gets spread out through the year.

[Ronald E. Mills:]

Okay. And then one just clarification, Michael. Have you talked about whether it'd be the acreage and/or the production level associated with the fairway and non-op positions that you may look to divest?

[Michael H. Lou:]

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's 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.

[Ronald E. Mills:]

Well, as far as getting that (40

[Michael H. Lou:]

Exactly.

[Ronald E. Mills:]

I'll let someone else jump on. Thank you.

[Michael H. Lou:]

Thanks.

[Thomas B. Nusz:]

Thanks, Ron.

[Operator:]

And our next question comes from Jeoffrey Lambujon from TPH. Please go ahead with your question.

[Jeoffrey Restituto Lambujon:]

Good morning. Thanks for taking my questions.

[Thomas B. Nusz:]

You bet.

[Jeoffrey Restituto Lambujon:]

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 a hedging standpoint?

[Michael H. Lou:]

Yeah. We're given kind of the two 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 what 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 it, one-year cash paybacks because they're pretty strong, kind of recycling cash at a very fast rate. So, very strong projects on the E&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&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 we've been very kind of systematic and we layer into that hedge kind of 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.

[Jeoffrey Restituto Lambujon:]

Got it. 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 is 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 that's kind of in the extended core bucket, accelerating the delineation of the Delaware, infrastructure build-out, shareholder returns, how do you think about that ranking?

[Michael H. Lou:]

Yeah. 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.

[Jeoffrey Restituto Lambujon:]

Thank you.

[Operator:]

And our next question comes from Paul Grigel from Macquarie. Please go ahead with your question. Paul Grigel - Macquarie Capital (USA), Inc. Hi. Good morning. I guess, focusing on the Delaware side, kind of a two-part on the completion side. One, do you see there is any risk either on the cost front or the logistic front in using spot crews down there right now? And what would be the desire to bring in what would potentially either be the second 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?

[Taylor L. Reid:]

You bet. 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 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. And we're really open to either. I mean, we want to make the best decision from a 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. Paul Grigel - Macquarie Capital (USA), Inc. Okay. And then, I guess a follow-up question on the incentives. 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?

[Thomas B. Nusz:]

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 it on a go-forward basis. 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 ultimately it's got to be – we've got to come up with a system that helps the organization align to ultimate performance. Paul Grigel - Macquarie Capital (USA), Inc. 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. Is that...

[Thomas B. Nusz:]

Well, yeah. Well, yeah, basically, I mean our organizational targets and metrics with our board are already set for 2018. So, obviously, because of that, it would be 2019 at the earliest. Paul Grigel - Macquarie Capital (USA), Inc. Okay. Just wanted to clarify. Thank you.

[Thomas B. Nusz:]

Yeah. You bet. Yeah.

[Operator:]

Our next question comes from Nitin Kumar from Deutsche Bank. Please go ahead with your question.

[Nitin Kumar:]

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, et cetera, you might be trying with those DUCs?

[Taylor L. Reid:]

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 million to $11.5 million range and still working on what the wells are going to look like. We're actually closed on Valentine's Day. So we now officially own the asset, but we're in a transition period with Forge, 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 a 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 16 to 18 wells I was just talking about, we'll drill 16 to 18 and then complete 6 to 8 wells. So you'll have around 10 DUCs that we'll 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 Spring's wells, focus being on acreage holding, testing intervals across the position and then also doing some small pilot spacing test.

[Nitin Kumar:]

Got you. And then just in terms of the midstream, seems like the $230 million to $270 million 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?

[Michael H. Lou:]

Yeah. We're working the midstream side on the Delaware side. There are a lot of options out there, both internal options as well as third-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'd see that'd be a big opportunity for the partnership to be involved with. So I think that's how you can think about that.

[Nitin Kumar:]

Great. Thanks, guys.

[Michael H. Lou:]

Thank you.

[Operator:]

Our next question comes from John Aschenbeck from Seaport Global. Please go ahead with your question.

[John W. Aschenbeck:]

Good morning. Thanks for taking the question. I've got a follow-up regarding your updated inventory estimates in the Bakken. I was wondering how that affects your outlook for terminal 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?

[Taylor L. Reid:]

Yes. So it's a good question. And just to kind of orient, if you look at the activity levels up in the Bakken and the Williston, and you think about the growth that we've been exhibiting, so exit-to-exit, I think Michael talked about in his comments was around 18%. And just in the Williston, it 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 the kind of growth profile we've been seeing in the Williston, spend within cash flow, and then really add to that down in the Delaware.

[John W. Aschenbeck:]

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, the type curves from that formation? I noticed you're sticking with the legacy 4 million pound job in 2018. So, is it just fair to stick with the legacy type curves there?

[Taylor L. Reid:]

Yeah. We didn't put any updated Three Forks 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.

[John W. Aschenbeck:]

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?

[Taylor L. Reid:]

No. We actually continue to have co-development in the Bakken and the Three Forks in some areas. But as you get outside of, for example, the place where we're most focused on and continue 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.

[John W. Aschenbeck:]

Okay. Great. Appreciate the color. Last one from 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?

[Taylor L. Reid:]

You'd 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. And in the core, it's about 70% Bakken.

[John W. Aschenbeck:]

Okay. Great. Appreciate the color. That's it for me. Thanks.

[Operator:]

Our next question comes from Phillips Johnston from Capital One. Please go ahead with your question.

[Phillips Johnston:]

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.

[Thomas B. Nusz:]

Yeah. 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.

[Phillips Johnston:]

Okay. And then the 2,500 GOR for the Wild Basin, is that the same stuff?

[Thomas B. Nusz:]

It is...

[Michael H. Lou:]

It's not that different early time.

[Thomas B. Nusz:]

Yeah. 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.

[Phillips Johnston:]

Okay. Perfect. Thanks, guys.

[Operator:]

And our next question comes from Dan McSpirit from BMO. Please go ahead with your question.

[Daniel Eugene McSpirit:]

Folks, good morning. What is the PDP decline rate on the oil and gas streams today in the Williston Basin?

[Taylor L. Reid:]

Well, the PDP decline, over the downturn, we really slowed activity down. We were kind of in the low-30s and got down to around 30%. We got down to two rigs and had less activity. As we've ramped activity back up here, that decline has steepened a bit. So now it's more in the 35% to 40% range and that'd be for 2018.

[Daniel Eugene McSpirit:]

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?

[Taylor L. Reid:]

Yeah. So the spacing assumptions, we think, were pretty conservative. But generally, in an interval, it's six wells, yeah, 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.

[Daniel Eugene McSpirit:]

Very good. Thank you. Have a great day.

[Taylor L. Reid:]

Thanks.

[Thomas B. Nusz:]

All right. Thanks, Dan.

[Operator:]

And our next question is from David Deckelbaum from KeyBanc. Please go ahead with your question.

[David A. Deckelbaum:]

I just had a quick follow-up, guys. Michael, I think you said the indications have been really strong on the fairway sales. And I know that you guys came up with sort of an internal target of $500 million that maybe was somewhat arbitrary. Given the improvement in the inventory, will you guys be willing to part with the entire fairway if the appetite was there?

[Thomas B. Nusz:]

Yeah. 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, 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 million, there's more than that in the bucket, and we'll just have to see how that plays out.

[David A. Deckelbaum:]

Okay. Thanks, guys.

[Thomas B. Nusz:]

Thanks, David.

[Operator:]

And, ladies and gentlemen, at this time, we 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.

[Thomas B. Nusz:]

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.

[Operator:]

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.