Good morning. My name is Phil, and I will be your conference operator today. At this time, I'd like to welcome everyone to the Q2 2017 Earnings Release and Operations Update for Oasis Petroleum. All participants will be in listen only mode. After today's presentation, there will be an opportunity to ask questions.
Please note this event is being recorded. I will now turn the call over to Mr. Michael Liu, Oasis Petroleum's CFO to begin the conference. Thank you. Mr.
Liu, you may begin your conference.
Thank you, Phil. Good morning, everyone. This is Michael Liu. Today, we are reporting our Q2 2017 financial and operational results. We're delighted to have you on the call.
I'm joined today by Tommy Muse and Taylor Reid as well as other members of the team. Please be advised that our remarks, including the answers to your questions, include statements that we believe to be forward looking statements within the meaning of the Private Securities Litigation Reform Act. These forward looking statements are subject to risks and uncertainties that could cause actual results to be materially different from those currently disclosed in our earnings release and conference call. Those risks include, among others, matters that we have described in our earnings release as well as in our filings with the Securities and Exchange Commission, including our annual report on Form 10 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 also make references to adjusted EBITDA, which is a non GAAP financial measure. Reconciliations to adjusted EBITDA to the applicable GAAP measures can be found in our earnings release and on our website. We plan to file our 10 Q today following this call, and we will also reference our current investor presentation, which you can find on our website. As we discussed on our last call, we issued a press release in May indicating that we decided to move forward with an MLP IPO for a portion of our mid stream assets. And due to securities law restrictions and advice of our attorneys, once again, we will be unable to discuss this development, and we know that you can appreciate that.
Through our public filings, you are able to see more information with respect to the transaction on the SEC's website. At this time, we cannot provide further comment. With that, I'll turn the call over to Tommy. Good morning and thank you
for joining our call. The Oasis team put together another solid quarter, bringing our total year to date completion count to 28 and preparing us for the increased completion activity in the second half of twenty seventeen as we discussed in our May call. We completed 15 wells in the quarter with 11 of those being completed with £10,000,000 of proppant or higher. Our production volumes were roughly flat with the Q1 as we continue to focus on cash flow neutrality in our E and P spend. The team did a tremendous job in the quarter establishing strong momentum going into the second half, where we have seen some firming in oil prices coupled with operational production averaging over 66,000 BOEs per day during the month of July.
We have the execution plan and the services in place to keep moving in the right direction and with that positive momentum to continue as you will hear from the team today. Setting us up to achieve our targeted exit rate for 2017 of 72,000 BOEs per day and we're on pace for a very solid 2018 as well. Back in May, we also announced our intentions to redeploy our 2nd internal frac spread and to optimize our completion schedule around the inclusion of that second OWS fleet in addition to our 3rd party crews. What we've seen in the market since then strengthens our conviction around that decision and supports our strategy of select vertical integration. While this provides us a natural hedge on service cost inflation, we feel it also provides a more balanced risk sharing relationship with our 3rd party service providers in terms of capital costs and input elements.
We look forward to starting operations of the 2nd crew in the next few weeks. We continue to experience encouraging results from increasingly higher intensity completions and are starting to enter a phase of optimization at least in the core with respect to cocktail, mechanics and overall capital efficiency. Wells incorporating our latest generation of high intensity completions in Wild Basin continue to perform well and we are now analyzing early time data from new tests in Indian Hills. Our current completion activities are expanding this footprint further as we've now moved on to Alger and Red Bank where we have already seen some encouraging results like the teal well at the north end of Alger just off of South Cottonwood. This is complemented by our other operator activity in areas such as Eastern Red Bank, West Indian Hills towards the Montana border and even on the western border of our large Cottonwood block on the east side of the basin.
Our focus on capital efficiency through the commodity cycle translates into financial returns as well. We've not been trying to grow at any cost, but have instead spent our energy improving the overall capital efficiency across our entire program. We remain focused on drilling wells that generate full cycle value and on acquisitions that create long term accretion to our shareholders. While we certainly want to grow the company and are excited about our current trajectory, Our view is that growth is an output that is derived from the quality of our asset base coupled with the focus on our balance sheet and the efficiency with which we manage both. Like everyone else, we're trying to understand what the rebound could look like after a challenging couple of years, and it's important to keep that at the forefront, especially in the choppy macro environment we still see today.
The team did a great job when prices fell in late 2014. We made swift decisions to power down in an orderly manner, avoiding all but negligible termination penalties, while transitioning to a cash flow neutral program in 20152016 that kept production flat in a $45 world. With our gains in capital efficiency, we can now keep volumes flat or grow nominally within cash flow in a $40 world and deliver attractive growth rates in a $50 world. We will continue to hedge to manage our risk around that just as we did in 2015 2016 and you can see that our overall hedge book has grown since May. We now have hedged about 65 percent of our oil volumes in the second half of twenty seventeen and have about 22,000 barrels of oil a day hedged in 2018.
We were basically cash flow neutral in the first half of this year on E and P spend of about 200,000,000 which excludes infrastructure spend. Additionally, we expect to be continue to be cash flow neutral on E and P spend in the second half of the year as we ramp up activity. Our track record also speaks our disciplined strategy and our focus on improving oil economics across our position through continued innovation, operational excellence and our vertical integration. With that, I'll now turn the call over to Taylor. Thanks, Tommy.
We had a strong end to the 2nd quarter, which sets us up well for the second half of the year.
We completed 15 gross, 10.8 net wells with 60% of these completions being done in June. In fact, about 40% of the completions for the quarter were done in the last 2 weeks of the month. During our last call, we signaled that we would come in relatively flat to 1Q for the Q2. In fact, we came in just a little under the mark. Breakup impacted the pace of completion activity in parts of April May and resulted in the backloaded completion cadence just mentioned.
In addition, we had more wells offline than normal in Q2 as we came out of winter and breakout. We increased workover activity in May June to work the backlog of wells offline back down. We'd originally expected to be flat quarter over quarter and these two factors cost us around 1,000 to 1500 BOEs per day. More recently, volumes were over 60 6,000 barrels of oil equivalent per day as benefits from the late completions and workovers kicked in. You will notice that we experienced a slight decrease in our oil cut in the 2nd quarter.
This is driven by an increased percentage of our total production coming from Wild Basin. As previously mentioned, Wild Basin has a higher gas to oil ratio than our other properties in the basin and about 65% of our year to date completions have been in Wild Basin. As the impact of wells completed in other areas with lower GORs increases, that balance should normalize. Our 78% oil production guidance for the year remains unchanged. On the completions front, we continue to enjoy the benefits of our pressure pumping business.
OWS continues to perform at high efficiency levels, which impacts our well cost and our ability to bring wells online in a timely manner, while also ensuring quality and availability of service. This has enhanced as the frac services market tightens and confirms our decision to redeploy our second OWS fleet. We will bring that spread back online in a few weeks and look forward to bringing the majority of our completion work in house. On the well cost front, we continue to see a tightening of the market during the Q2. The cost of a £4,000,000 50 stage completion is now $6,500,000 The cost of a £10,000,000 50 stage completion currently runs $7,300,000 We think inflation will continue to rise in the second half of the year, but the pace may be slowing as shown by the availability of more service options than what we saw in April May.
Our year to date CapEx is in line with our guidance and we expect the remainder of 2017 E and P and other capital to be as well. It continues to be an exciting time in the evolution of the Williston Basin as completion technology advances and well performance improves. As Tommy mentioned, we continue to test bigger jobs as well as stages per job, perch clusters and perch spacing, diverters and other techniques to optimize our fracs. We now have a good sample of bigger jobs in Indian Hills, including 220,000,000 pound test and are excited about the early time results. We continue to test the upper bounds of proppant loading and in the last few days we completed our first 30,000,000 pound well in Wild Basin.
Also, we now have much more production data on our previous tests in Wild Basin and have updated the charts on Page 5 of our current presentation. What you're consistently seeing in our latest generation of high intensity wells is that these bigger jobs flow for longer periods of time than the smaller jobs. Both wells exhibit flat production profiles early in their life while they are choked back and rate restricted. The bigger frac simply maintained its profile for longer. This is all a result of the wells being facilities constrained by the local central tank batteries until they begin to decline.
Remember, we design our facilities to cost effectively capture early production, not just for the peak. Our John Drew 3BX well in Wild Basin 20,000,000 pound test is a great example of this performance. It was choked back early in its life awaiting gas infrastructure and is producing today at rates after 14 months or similar to its early time production. As you can see, this well has been and is a great example of the benefits of the larger frac jobs. Again, it's still early innings as we continue to gather and analyze more data with longer tenure.
We are also excited for results from several of our peers who are testing these larger completions in and around our extended core and Fairway acreage. We also have several large completions in our Red Bank area scheduled for the coming months and are currently planning tests in other extended core fairway areas for 2018. As we move into the second half, we are excited about the program ahead. We are confident in our ability to execute on the program as we have the resources and the team in place to do the job. With that, I will now turn the call over to Michael.
Thanks, Taylor.
As you probably know, the Dakota Access Pipeline or DAPL is now online and its contribution to basin takeaway capacity is making a significant impact on basin wide differentials. The line started moving oil in June and now in August we are seeing the full impact of the additional capacity and demand in our differentials. While differentials tightened from $5 per barrel in the Q1 to $3.50 in the second quarter, we saw only a partial impact in our 2nd quarter differentials and we expect to see a more substantial impact to 3rd quarter and beyond. Differentials in June were down to about $3 per barrel and recently we've had some sales well below that. On average, we expect differentials of $3 or better for the remainder of the year, keeping us well within our $3 to $4 annual guidance range.
We've delivered basin leading differentials over the past couple of years by getting crude onto large gathering systems and maintaining maximum optionality amongst delivery points. While we certainly have direct access to DAPL through both third party and proprietary systems, the overall increase to basin away has put significant pressure on basin wide differentials and specifically for producers who have not committed production under long term contracts. As a reminder, Oasis has 85% of its barrels that are not under long term contracts. GM and T increased slightly this quarter, but was still within our guidance range on the year. Much of that increase is related to newly available long haul pipeline charges as we access better markets and is offset by the improved differential yields.
Lease operating expense per BOE also increased slightly. It was a function of our lower production this quarter coupled with higher workover rates that Taylor mentioned previously. We expect to work LOE back down within our guidance range as we materially grow production in the back half of twenty seventeen. The team has done a great job maintaining the stellar efficiencies that we achieved over the last 2 years and positions us to increase activity in the second half of the year at extremely strong full cycle returns for our investors, which will also continue to improve the balance sheet. We're off to a great start in the Q3 and we are on pace to efficiently achieve our plans.
We had many discussions over the past several months during periods of lower oil prices on how we would react in those lower oil prices. If the commodity heads south for a prolonged period, we maintain the optionality to reduce activity in very short order. And as Tommy mentioned earlier, we can still grow modestly within cash flow in a $40 world.
I want to close by echoing
Tommy's comments on the importance of financial discipline. Regardless of where oil prices trade, we will continue to focus on shareholder returns and optimizing capital efficiency. We made material improvements to our balance sheet throughout the downturn and we see it continuing to improve organically as we continue to as we execute our plan over the coming years. With that, I'll turn the call back over to Phil for questions.
Thank you. We will now begin the question and answer session. The first question comes from Neal Dingmann with SunTrust. Please go ahead.
Good morning, guys. Hey, Tommy, for you or Taylor, could you just remind me with the cadence, I know you guys have some larger cadence as it pertains to some of these £20,000,000 £30,000,000 jobs. I know I think more on the 20 side. What are sort of the plans for the rest of the year and kind of how you perceive even the £30 jobs at this time?
Yes. So on just straight cadence, so now we've got 28 for the first half of the year. It's kind of consistent with what we said in May. So you get 48 for the second half of the year and kind of split it between the 2 quarters. So 24 roughly in each of the last two quarters and Taylor can give you some color around prop intensity on those.
So, as we said, we've got 30,000,000 pound job and so far and has tested a number of the 20,000,000 dollars s for the rest of the year. As Tommy said, we're going to do more wells in about roughly 60 percent of the whole program will be actually a little bit more than that, but around $60,000,000 be over the £4,000,000 job, but still shouldn't have a £10,000,000 average and we're just going to have a mix of different jobs to test the full range as the year goes on. The £30,000,000 job in terms of performance, it has just now come online. And as I talk about with all these big wells, they're rate restricted early. So it just looks like the other wells until it gets further out in time.
Got it. And just one last thought, if I could. Could you talk about, again, that second spread, I forget that you did talk about the timing of that coming, but just talk about the size of that and given what you're seeing now in these jobs, any thoughts about adding horsepower to the original ones? Again, I forget what the size of each were, but more it's about the size of each and if you would add more horsepower to the first. Thank you all.
Yes. We it'll come on here within the next 2 weeks or so. And 2 spreads will be the same size. We did the second spread. We laid it down last year in February and to bring it back, we actually added some horsepower to the spread.
And so as we talked about commissioning getting back up and running and at the same capacity and size of the first spread will cost us roughly $15,000,000 but all that will be really be in place when we bring it on here in a couple of weeks.
Thanks again, guys.
You bet. Thanks, Neil.
The next question comes from Brad Heffern with RBC. Please go ahead.
Good morning, everyone. On the workovers for the quarter or for last quarter, was there any reason that you were seeing more need for that than expected? And was there anywhere that, that work was particularly concentrated?
So the workovers really are a function of just winter and breakup. And we tend to have more you can have more wells down in the winter period just because of operating conditions. And then combining that with cycle times really being longer, you end up with more wells going down and cycle times are just winter days or shorter, harder to get as much work done in a day. So it takes more equipment to get all those wells back on. So we ended up getting a bit of a backlog that we really worked down in April May.
So I mean in May June, once we got kind of past break up, got more rigs out there and worked that backlog down. And in fact, as you look in July, you really see the workover count start to come down. So it's not a reflection of any particular area. It's kind of spread across the whole position. And as we mentioned, we did a big slug of those, got the benefits of getting those wells back online and should see it kind of moderate for the rest of the year.
Okay. Thanks for that. And then secondly, can you talk at all about the cadence for OMS spending? It was kind of heavy this quarter.
You're talking about which part of the spending? You're talking about capital?
Yes. Yes. OMS spend
is in line with expectations. Obviously, you're going to do a little bit more through the good months here over the summertime. And Taylor mentioned it, I think, in his prepared remarks, but capital overall is in line with expectations year to date and we think for the full year as well.
Okay. Thanks all.
You bet.
The next question comes from Jason Gilbert with Goldman Sachs. Please go ahead.
Hi. Thanks for taking my question. Question on Wild Basin, the higher GOR there, was that expected? And how do we think about the gas mix going forward?
Yes. In Wild Basin, we've kind of always said that that area has a higher GOR. So it's about a 70% oil cut, about a 30% gas cut. The rest of the basin is closer to 85% oil and 15% gas. And so as activity is a little bit more focused for the last couple of years in that Wild Basin area, the gas mix is going to increase.
However, what we've said kind of through this year is that as our activity starts to get more balanced between Wild Basin and other areas, you're going to start to see that oil and gas mix kind of moderate in that 78% for the full year. So not surprising that it's a little bit more gassy in the second quarter because 65% of the wells in the first half were in that Wild Basin area. Throughout the rest of the year, it's going to be a little bit more balanced.
So the older vintage wells across the play are performing in terms of oil cut exactly or as you expected, is that safe to say?
Yes, I think so. Yes.
Yes, they're pretty much performing as we would expect.
Great. And second one, can you talk about the M and A environment in the Williston right now? I mean, Halcon I think surprised most of us to the upside on the print they got. And I'm just wondering, are you guys more of a buyer or seller of assets in this market?
Yes. I would say that it's consistent with what we've always done is SM the SM transaction at the end of last year is a great example is that where we have opportunities to bolt on in and around our core blocks, then we'll do that. And so we continue to look for little we get little things that are $1,000,000 or $2,000,000 here or there, occasionally something big like SM will pop up, but we're always looking to bolt on.
And last one, if I may. You mentioned if the commodity heads south, you could reduce activity. What's could you get more granular on the price at which you'd go from 4 rigs to 3 or on the upside 4 rigs to 5 maybe?
Yes, I think it's I mean, it's consistent with what Michael said. I mean, we've what we've been saying for some time is we're kind of managing this thing within a $45 to $55 band. And as it starts to head to $40, we can track to the same old scenario where we live within cash flow, kind of tread water on volumes. Maybe at this point at 40, we think we can probably grow volumes just nominally in that world and then the activities and output of it. So this year we had about 76 completions in that world.
We'd probably have somewhere in the range of 45 or 50, and we'll see where that goes. But also keep in mind too, we're continuing to build our hedge book. We're what was it Michael, 65% for the second half of this year and continuing to build the book. We're only at 22,000 for 2018 right now, but continuing to build that book next year to insulate us against that price. So but that's kind of how we're managing it, but that's consistent with what we've been doing.
Great. I'll turn it back. Thank you.
You bet. Thanks.
The next question comes from David Deckelbaum with KeyBanc. Please go ahead.
Good morning, guys. Thanks for taking my questions.
You bet.
Hey. Hey. Ted, I was
hoping, looking at the cost that you put up on Wild Basin, it looks like you're having more success with 50 stages versus 36 in the £4,000,000 jobs. Is that sort of the base case now for that £4,000,000 job is getting the tighter frac stage spacing there?
Yes, Dave. We've actually gone to 50 stages on all the jobs. So both the £4,000,000 and the bigger jobs, we just we're seeing better well performance with the increased stages, and we think better distribution in the frac.
Got it. And your comments, I think, on the John's read earlier about the well-being choked back early and how it's producing in a similar rate now. Based on
the data that you've collected, do you think
that there's an argument to choke these wells back further intentionally going forward?
We may be getting a we're looking at the data and trying to analyze and see if there is a a EUR longer term well performance benefit of chugging the wells back. It's driven really a lot by facilities at this point. We have done some testing with
managed
flowbacks on wells, really trying to capture some more of that data, but we don't have any conclusions at this point.
Good. I appreciate that. And just the last one, if I may. I think you mentioned that you're getting close to optimization for the program. I guess, can you kind of add some color to that as to when you feel like you'll have enough data in hand to make decisions on what your sort of generic recipe would be?
Yes. That it really continues to evolve. And what you've seen us do over the past year, we kind of have a base recipe that we're working off of. And right now, it's more like the average well is more like a 50 stage, £10,000,000 job and it's all sand and then we're testing a lot of things around that to understand what's going to be the optimal job going forward. And so if we see something like going from 36 to 50 stages, it's clearly making an impact and we'll make a move and make and blend that into our standard job.
So it's going
to continue to evolve as we go. Yes, David, in my comments, it's really focused around Wild Basin because that's where we have the most data. As we move to like currently Indian Hills and Alger and then recently up to Red Bank, I mean, that's much less mature in terms of knowledge with these higher intensity completions. Of course, we always look at what all the guys are doing around us, but that's still much more work in progress than in Wild Basin where we really have a lot of data at this point. Got it.
The next question comes from Ron Mills with Johnson Rice and Company. Please go ahead.
Hey, good morning. Hey, Ron. As you look at the high intensity fracs and how that builds into your projected growth for the second half of this year and even to hit your 2017 2018 exit targets, have you factored in any incremental uplift from the use of higher intensity fracs? Or what are some of the assumptions behind that growth profile versus how you're completing wells?
Yes, Ron, generally with the bigger jobs, we've factored in the benefits of doing them. But it's as you make a step up from a 4 to a 10 and to a 20, it's on a percentage basis and then we use a type curve. So when you look at some of these look on Page 5, some of the results from the wells as you get further out in time, some of those are probably outperforming what we've used on a percentage basis. When you look earlier time, especially these bigger wells, they're all flat profiles. And so we're actually modeling them that way.
So we've got flat production for an extended period of time. And then you'll see them outperform as that flat production continues. But I would say in general, we are definitely modeling for the bigger wells, but there's upside to what we're using just based on how they perform.
Okay. And the follow-up to an earlier question in terms of pace of completions, I know the second half is up significantly versus the first half. But relative to the second quarter, is the second half is the pace of completions expected to be pretty similar over each of the months, so therefore the growth profile be a little bit more linear than what we might have seen in the Q2?
Yes. I
mean, we're right on track with the math. I mean, if you looked at July, of course, being in the summer helps, but it should be more consistent. Go ahead.
Okay. Well, and then I'll say last I was going to ask, we've talked a lot about Wild Basin, but you're obviously starting to bring more wells on from the Alger Indian Hills and maybe Cottonwood areas. Where are you in those areas in terms of completion intensity and the outlook for activity spread between Wild Basin and those other areas?
So we've as we've stepped out to the other areas, we've been testing these bigger jobs as well. And as I mentioned, we've got, for example, in Indian Hills, we've got a couple of £20,000,000 frac jobs. And those are early times, so we haven't shown them yet. We'll show them next quarter as we get more data that's meaningful. In Red Bank, we've got a couple of the bigger jobs paid as well, so the £20,000,000 fracs and those will be done this quarter.
And then as you look at and then we'll when I say done, we'll get them fracked, get them on production. So meaningful production data is going to be on that Red Bank stuff probably late this year, early next year. And then when you look over on the east side of the basin, the teal well we've got in the presentation, that's the equivalent of a £20,000,000 job for a 10,000 foot lateral, great results on it so far. And then as we drill further south right now, we're in the Spratly unit and again, going to test a range of bigger job there as well. So Tommy mentioned it, the recipe may not be exactly the same in all the places, but we're starting out with what we've seen work well in Wild Basin, applying that and then we'll work on optimizing those jobs further.
But excited to see the results in these other areas.
Are any of those wells in areas that particularly in Red Bank that could pull more of your extended core into core like we saw last quarter?
Yes, that's really good point. The wells in Red Bank are really on the edge of what we're calling core. Some of them
are
just a little over what we call the boundary, but so it could impact an area around it based on the results that see. And on top of that, you've got a number of wells which we're tracking by other operators. Fairway that are being tested with 1,000, 2,000 or more pounds per foot of proppant. So we'll track those and talk about those as we get more data. And then as we go into 2018, we'll really push it out further outside the core into the extended core on our own pilots.
Great. Thank you very much.
Thanks, Ron.
The next question comes from Joshua Gale with Nomura Securities. Please go ahead.
Hey, thanks for taking the question. I know a couple of them have been answered already, but I was just wondering in terms of the differentials, if you could just highlight some of the flexibility that the integration with OMS gives you in terms of delivery points and how much that helps on a dollar per barrel basis day to day? Because across the space we're seeing some differences in differentials in your peers. And I just want to get a sense of what the strategic advantage is there.
Yes. And the differentials as we talked about really have stemmed from kind of a strategy that has gone back 5 or 6 years of getting all of our oil onto a large gathering system that has basically access to every way out of the basin, including DAPL, which has been the impact here recently. DAPL came in with 450 1,000 barrels of takeaway capacity, a lot of long term contracts associated with it. And so what it does is it brings a lot of demand for us as producers in the basin. And one of the things that our marketing team did a great job of is really kind of thinking through what the production in the basin was forecasted to look like as well as what the takeaway capacity was going to look like.
And we're in a situation where there's a lot of takeaway capacity in the basin with much lower production levels. So that's good for producers and it tightens our differentials, especially given that we are only we're 85% short term on our oil barrels. So we can actually move our barrels to the best price at any given time. So it gives us a chance to get very, very tight differentials and you've seen that in our results.
Thank you.
Great. Thanks.
This concludes our question and answer session. I would like to turn the conference back over to Tommy News for any closing remarks.
Great. Thanks, Phil. We're looking forward to the second half of twenty seventeen as we nearly double our completion activity from the year to date levels. The next 6 months represent the heart of the 2017 program and more importantly, lay the groundwork for everything to come in 20 18 beyond. The quality of the asset base we've built and the strength of the team we've assembled to develop it gives me great conviction around the future success of Oasis.
We're confident in our ability to execute and to manage our business prudently in what continues to be a constantly changing market. Thanks for joining us today.
The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.