Good morning. My name is Drew, and I will be your conference operator today. At this time, I would like to welcome everyone to the Fourth Quarter 2018 Earnings Release and Operations Update for Oasis Petroleum. [Operator Instructions] Please note, this event is being recorded. I will now turn the call over to Michael Lou, Oasis Petroleum’s CFO, to begin the conference. Thank you. You may begin your conference.

Thank you, Drew. Good morning, everyone. Today, we are reporting our fourth quarter 2018 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 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. The Oasis team continues to do a great job executing against the four cornerstones of our strategy that we laid out in 2017. Those are size and scale, portfolio diversity, asset quality and financial strength. This strategy continues to serve us well in the face of volatile oil prices and associated headwinds. Our management of E&P spending was in cash flow over the last four years has clearly demonstrated that Oasis has built and managed to withstand and even prosper in low price environments, given our deep inventory, which now spans two low-cost basins, our experienced workforce, our financial management and our ability to manage business risks. We designed this business to have the flexibility to efficiently ramp up and down, depending on market conditions with an aim to generate free cash flow in the E&P business down to WTI prices of $45 per barrel. Taylor will provide more color in a moment, but I want to highlight a few key points regarding 2018 for you this morning as we wrap up the year. First, our Williston Basin asset performance remained strong as we completed 28 wells in the quarter, and we’re able to capture more gas in Wild Basin. In aggregate, our fourth quarter volumes averaged 88,300 Boes per day in line with midpoint guidance. Second, OMP successfully started its 200 million a day gas plant in early December bringing our total processing capacity to about 320 million per day and making OMP the second largest natural gas processor in the basin. Congratulations to the Oasis team for a huge win here. They did a great job using their sub-surface knowledge to anticipate increasing gas production and tightness in gas processing capacity. This allowed Oasis to stay ahead of the…

Thanks, Tommy. In 2019, we expect to spend between $540 million and $560 million of E&P in other capital across both basins, with about 85% of net capital for drilling and completions. The program should deliver production of about 86,000 Boes to 91,000 Boes per day for the full year as well as in the fourth quarter of 2019, essentially in line with the fourth quarter of 2018. Our oil cut is expected to average approximately 72% in 2019, which implies a cut of about 71% for the fourth quarter. The decline in oil cut versus 2018 reflects a few different factors, including the start-up of our new gas plant, which allows Oasis to capture higher volumes. Our program in the Williston that was more focused on Wild Basin, which has a higher GOR than our PDP base even though the Wild Basin wells are some of the best oil producers in the Williston and a restrained Delaware program, which has a higher oil cut. In 2018, Oasis delivered strong production growth from new wells, especially later in the year. These high-rate wells also have fairly high first year declines, which directly impacts our base decline, which we now estimate at about 40% exit to exit. Base declines get shallower in 2020 and beyond. In the Delaware, we’ll steadily become a larger part of the development program. As a result, overall oil production in 2020 should flatten out or even slightly grow based on maintaining a program in a $50 world that generates free cash flow. In the Williston, we are currently running three rigs that are expected to drop to two in the next month or so. We quickly adjusted our plan in the fourth quarter and released two rigs so we have effectively adjusted our 2019 plan from…

Thanks, Taylor. As you’ve seen in the years past, our low-cost assets and top-notch operational team delivered strong performance. This past year, we high graded our asset base further through a series of divestitures and new bolt-ons in the Delaware. We are in a great position to enhance returns, drive capital efficiency across our deep portfolio, and generate significant free cash flow. Since 2015, Oasis has been dedicated to living within E&P cash flow. We created OMP in 2017 to help finance Midstream spending, and in 2018, used a portion of divestiture proceeds to expand the D&C program. During the fourth quarter, we sold down Oasis’ interests in Bobcat and Beartooth DevCos for $250 million, which resulted in Oasis receiving approximately $170 million in cash and $3.95 million in OMP common units. The cash portion of the sale covered Oasis Midstream spending in 2018. As we turn to 2019, the current plan calls for Oasis to generate approximately $150 million of free cash flow at $50 WTI oil price, which increases to approximately $230 million at $60 per barrel. Slide 9 of our investor presentation highlights our free cash flow position and bridges the components of our free cash flow. We define free cash flow as standalone E&P EBITDA, plus Oasis ownership of Midstream and distributions from OMP, minus cash interest, minus total CapEx attributable to Oasis including Midstream. The Midstream portion of Oasis CapEx is minimized due to a recently approved arrangement between Oasis and OMP, where OMP will fund Oasis portion of growth capital in our Bobcat DevCo. We believe this arrangement is mutually beneficial for both Oasis and OMP as OMP can increase its ownership position at a fair value and Oasis is able to focus its spending on its E&P business. As a result of this…

We will now begin the question-and-answer session. [Operator Instructions] The first question comes from Michael Hall of Heikkinen Energy Advisors. Please go ahead.

Thanks, good morning. I was curious if you could provide just a little additional color on kind of the cadence of completion profile over the course of the year. I’m just trying to think through obviously with the rig count coming down, how that will kind of play into your normal seasonality if completions in the Williston and I’m trying to square that also with the kind of flat 1Q 2019 versus 4Q 2018, just trying to think through how the momentum from the back half of 2018 doesn’t carryover a little bit into the first quarter 2019?

Yes, I think you’re thinking about the right way. The cadence is like we normally see in the winter is going to be a little slower in the first quarter. So for Williston, 70 wells, you’re going to have it’s not evenly distributed. Like I said, I don’t know may be 10, 15 well kind of range, and then you can spread the rest of the well pretty evenly across the last three quarters of the year. Obviously, less completions in the first quarter, but we had a number of wells that we brought online, 28 wells as Tommy talked about and a number that were late in the quarter so some of that’s spilled over and it will just help us to keep volumes flat into the first quarter then like we talked about we’ll pick up activity again.

Okay. And as we kind of think through the oil rate trajectory, you pointed to 71% oil mix in the fourth quarter 2019, which should be kind of down a little bit, exit to exit. Are you growing out of the year so like is there a low point in the year that comes prior to the fourth quarter? Or are you declining through the course of the year on oil volumes? And when would you think you would flatten that out, if the latter is the case?

Yes. So when you talked about the cuts and the end of last year, fourth quarter you’re more like 76%. And the thing that’s going on in Williston, we’ll bring -- we brought on the plant in December. So quite a bit more processing capacity here at year-end, but just for really a month and then you get that full treatment for the whole first quarter with that new plant on so a bit of a dip. If you just did the numbers we talked about, it went down pretty symmetrical here over – 73%, 72% at the midpoint of the year and then 71% at year-end, which will imply as we talked about there is a bit of a drop off in oil volumes for Williston, but then you get offset with increasing oil volumes in the Delaware. So exit to exit, all that combined, a bit of a drop in oil, but then as we also talked about as we get into 2020 the decline profile looks different. So you go in 2019, the base decline is about 10% and that as you have less of the new wells, that should be the production be dominated by new wells that moderates into 2020. And so that’s -- we think that will allow us to keep our oil volumes flat to slightly growing in 2020 relative to the exit in 2019.

Okay. That’s helpful granularity. Thanks. And then, I guess, last one and just may be bigger picture, stepping back as you guys think about 2020, kind of holistically, I guess, how are you thinking about that in the context of getting back to potentially some growth or a free cash flow really still the emphasis? And what sort of activity do you need to have in the Delaware in 2020 to keep that acreage position whole?

Yes, from -- as far as the acreage hold close to the pace that we’re drilling this year can do that for us. But what we expect -- you saw from last year to this year, we stepped it up a bit in the Delaware. And then as you look at going into 2020, likely going to be going into more full development 2020 or close to that time. Again, the activity levels probably going to pick up, again, in the Delaware. Overall, with respect to the free cash flow generation, our expectation is to continue to generate free cash flow, certainly, in this $50 environment that we’re in, we can continue to do that. And like as I said, whole volumes is flat. If you can get into a higher price world, we have the opportunity to move activity up a bit. But, again, it’s going to be focused on continuing to generate free cash flow.

All right. And thanks very much.

As Michael talked about that number, it’s in the deck. You can look at the slide that shows that each of the higher price cases we generate more free cash flow, and that’s on Page 9 of the presentation.

Got it. Thanks, really helpful, guys. I appreciate it.

The next question comes from Derrick Whitfield of Stifel. Please go ahead.

Good morning, all. I definitely want to apology you guys on a strong and capital discipline outlook. With respect to the Williston, could you share with us your thoughts behind the name change from core and extended core to Top-Tier? Is it simply the results on the former extended core approaching a level that’s very similar to past core returns?

Yes, no, that’s, you’re on the right track. If you -- people that are new, if you look on Page 5 of the deck, you will see that we’ve really just got what we’re calling Top-Tier than additional upside acreage. And the way we had this classified over the past three or four years, we had this core and extended core concept. And the break between those two core was $40 breakeven or below extended core was $45, and so a $5 difference between those two classifications before there was a lot of these higher intensity stimulations outside the core made sense. Now as you look, yes, I actually direct you to Page 10 and 11. The map on Page 10, you can see that, well, there’s a bunch of these enhanced completions really all over the basin and all over these areas that we’re now calling Tier 1, and the results of the wells are pretty impressive. If you look on Page 11, you will see for South Cottonwood, Painted Woods, and for Montana how the more recent completions so there are 2016 plus completions in our recent test in Painted Woods compared to all the completions done for all operators in the basin since 2017. And keep in mind, most of that activity is in the core. So it really compares favorably. So we just think that highly economic position is expanded over a bigger part of the basin and are going to this single Tier concept, which we also think is really more in line with our peers.

Got it. That makes sense. And just a follow up for you, Taylor. Speaking to pre-wells you’re referencing on Slide 11, how close are those designs to what you would consider best practice? And could you also speak to the potential timing for your planned enhanced completion test on Montana and South Cottonwood?

So when you look at the pre-wells, different operators are doing different things like most of this activity since 2015 has been concentrated in the core and for the most part, everybody has gone to high intensity completions, and they’ve got different variances of those completions, but a lot of that is slickwater. And then the exact sizes of those kind of change. So pretty much everybody has made the shift at this point to high intensity completion seen that in liners and also doing a plug and perf completions. So we think it’s a pretty representative of what we’ve been doing. So I think a good competitor. In terms of drilling additional wells in Montana and South Cottonwood, we’re evaluating that. And so this year or sometime next year, you’ll probably see that happen. This -- it’s not unlike what we did in Painted Woods. If you guys remember, we moved Painted Woods into the -- an additional Tier of inventory we moved it up based on third-party results we saw in the area. And then in 2017, we went in and drilled our own wells, and has seen as good or better results than what we saw from competitors. So you can expect a similar approach for both South Cottonwood and Montana.

Very helpful. Thanks for your comments.

The next question comes from David Deckelbaum of Cowen. Please go ahead.

Good morning, guys. Thanks for taking my question. Michael, congrats on consummating the deal with OMP on the CapEx agreement. I’m curious how you’re thinking about that going into 2020 and beyond? Should we think about this as sort of a perpetual structure that you could turn to until you get done with ownership threshold before you would be, I guess, effectively losing control?

Thanks for that David. This arrangement is clearly only for this year. However, what we have said in the past from an Oasis standpoint is that, we want to spend free cash flow. We either want that to go back to the balance sheet at the parent level or go into our E&P capital spending program. And that’s how we continue to think about it. So midstream capital for the most part, we do want to be spent at the MLP level. Whether it’s through a drop down or it’s a capital expenditure arrangement like we settled on now, that’s kind of how we’re thinking about it. So we’ll see how this continues to work for both sides. We think it’s a win-win for both sides and it will be great. And if that continues, obviously we can think about that for 2020 and beyond as well.

That’s helpful. Appreciate that. And then just on the 2019 plan and, Taylor, you talked about the oil mix and gave some thoughts on to oil growth going into 2020. And sounds like you would be adding some activity in the Delaware? In your sort of high level planning now on sort of a $50 world, does that come at the expense of Williston capital going beyond 2019? Or I guess, another way, at what point do you see that Delaware becoming sort of almost an even capital allocation to the Williston?

Yes. So the first question around activity levels and impact on the Williston. Yes, if we continue to be at $50 world, the program is going to be fairly similar. One of the things to keep in mind that if we are in a $50 world, you’re going to continue to see deflation, and so we think that’s helpful in being able to execute on a similar program. We also would expect that will continue to improve our efficiencies and cycle times and bring down cost, especially in the Delaware, and we’re early on that asset. We’ve been operating it now for a year, have made good strides. But we’ve got a path to continue to improve on that. And so as we pick up a little more activity in the Delaware, yes, there is going to be some offset in terms of activity, if it’s the same overall program. But there’s also benefit to cost deflation, and then just overall efficiencies in a lower price world, that won’t make that as big of impact, so it might be otherwise don’t. It’s just directional. I don’t have specific numbers at this point, but that’s how we’d be thinking about it.

And David, something to add to that is Taylor did mention earlier in his prepared remarks about the declines -- the base declines are starting to flatten as well. So over time, you’re not going to need as much capital in the Williston to continue to maintain production levels there. It’s got a great inventory base as we’ve already talked about. And so we think we can maintain that with less and less capital. It’s going to generate a lot of free cash flow that will originally be re-allocated towards Delaware some before it gets to free cash flow itself.

And then as far as, how long is it going to be before you’re spend in even capital between the two basis, well, that’s a number of years out and just really for us to give a view on that at this point.

Thank you guys for all the color.

The next question comes from Ron Mills of Johnson Rice. Please go ahead.

Good morning, guys. Taylor, maybe for you, in the Permian, especially you talked about some of the test you’re doing, just provide a little bit more color on what 2019 looks like in terms of additional delineation of the Wolfcamp B, along with the the 3rd Bone Springs? And is this also the year when you potentially start testing the co-development of all three other zones like you did in the upper and lower A tests?

Yes. Ron, it’s a good point. We are going to do some individual interval test of the Wolfcamp C, the Wolfcamp B, Bone Springs 3, like you talked about. But then with the eight-well pilot that we talked about, drilling eight wells in spacing, we will test a number of those different intervals together all in a block to see how they interplay and what spacing will look like going forward. And that’s important for us, as we look to 2020 and beyond and get more of a development program going forward. We really want to understand how all those intervals interact in spacing and with the type of stimulation that we’re doing.

And do you think in terms of timing, you will have enough of that data in hand by the end of this year as you look to formulate your 2020 plan? Or is that something that really transitions over the course of 2020 and you potentially move to more of a full co-development program?

Yes, it’s going to be early results as we get into 2020. So we might be doing more pad work like that and then getting into really full development later in the year. But we’ll continue to evaluate it as we go. It’s important from efficient resource recovery standpoint, but also important from cycle time of capital efficiency, you just getting into pad operations is going to really help to continue to bring the cost down.

Okay, great. And then Michael for you, on the free cash flow side, what are the -- what’s the plan to use the free cash flow? My guess is initially to paydown debt. And I guess, if that’s the case, do you kind of have a targeted longer-term leverage ratio you’d like to achieve with that free cash flow? And how do you measure that versus the opportunity to do more or similar bolt-ons to what you did in the latter part of last year and in the Delaware?

Yes. Right now, the way we’re thinking about it is we need to continue to increase our financial strength. And we’ve always kind of talked about a two times debt-to-EBITDA level that we’re shooting for in a normalized oil price. So if you call it a $50 or $55 oil price kind of a normalized basis, that’s what we’re going to shoot for is under that two times. And so as we think about free cash flow generation, what we tried to show where -- what that might be in a $50 world, today, you’re more like $55, so it might look like in $55 and $60, and in those scenarios, trying to be thoughtful around service cost maybe being a little bit different as well in those different environments. So you’ll notice those don’t ratchet up perfectly with necessarily with EBITDA as we’re kind of adjusting inflation on CapEx too, but really looking at that as kind of bolstering the balance sheet and paying down debt at this point.

Great colors and milestone. Thank you, guys.

The next question comes from Brad Heffern of RBC Capital Markets. Please go ahead.

Hey, morning, everyone. I guess, kind of on the same thing for the 2019 plan. Can you just talk about what led to this being the plan versus maybe a plan that would have kept oil flat or maybe even a free cash flow neutral plan? What are the benefits of this versus the other option?

Look, we’ve had a big focus of start -- I think, Tommy’s got something to add, but we had a big focus on a minimum being free cash flow neutral. And as we continue to work the program, it became apparent that we could really keep our volumes flat and generate free cash flow. And we just thought it was a great use of proceeds. The capital efficient inventory in the basins really allow us to put a program like this out, which we think is tremendous.

Yes. I think having been in a position where we can keep volumes flat on an aggregate basis and generate free cash flow that we can bank to lay off financial alternatives versus operational alternatives, it’s a great place to be. We’ve talked about it for a long time. And just make sure that you get the dollar going to the next optimal place. And as Michael mentioned, I think, in the short term, it’s all going back to the balance sheet and providing more firepower.

Okay, thanks for that. And I guess, obviously as you slowdown, that lengthens the inventory life to some extent. Does that make you have a greater desire to potentially prune some of the longer-dated inventory?

We’ll see how the market is. It gives you flexibility for sure.

Okay, thanks.

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

Thanks, Drew. To sum it up, Oasis continues to execute on our long-term plan with our deep low cost inventory in the Williston, driving capital efficiency and allowing for free cash generation in a low price environment. In the Delaware, we continue to delineate our position and accretively grow our footprint, while preparing for full-field development. We have the team and the strategy in place to succeed and we look forward to delivering for all of our stakeholders. Thanks again for joining our call.

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