Good morning. My name is Phil. I will be your conference operator today. At this time, I'd like to welcome everyone to the second quarter 2017 earnings release and operations update for Oasis Petroleum. All participants will be in listen-only mode. Should you need assistance, please signal a conference specialist by pressing the star key followed by zero. After today's presentation, there will be an opportunity to ask questions. To ask a question, you may press star then one on your touch-tone phone. To withdraw your question, please press star then two. Please note this event is being recorded. I will now turn the call over to Mr. Michael Lou, Oasis Petroleum CFO, to begin the conference. Thank you, Mr. Lou. You may begin your conference.
Thank you, Phil. Good morning, everyone. This is Michael Lou. Today, we are reporting our second quarter 2017 financial and operational results. We're delighted to have you on the call. I'm joined today by Tommy Nusz and Taylor Reid, as well as other members of the team. Please be advised that our remarks, including the answers to your questions, include statements that we believe to be forward-looking statements within the meaning of the Private Securities Litigation Reform Act. These forward-looking statements are subject to risks and uncertainties that could cause actual results to be materially different from those currently disclosed in our earnings release and conference call. Those risks include, among others, matters that we have described in our earnings release as well as in our filings with the Securities and Exchange Commission, including our annual report on Form 10-K and our quarterly reports on Form 10-Q.
We disclaim any obligation to update these forward-looking statements. During this conference call, we will also make references to adjusted EBITDA, which is a non-GAAP financial measure. Reconciliations to adjusted EBITDA to the applicable GAAP measures can be found in our earnings release and on our website. We plan to file our 10-Q today following this call. 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 midstream assets. Due to securities law restrictions and the 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. 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 2017, as we discussed in our May call. We completed 15 wells in the quarter, with 11 of those being completed with 10 million pounds of proppant or higher. Our production volumes were roughly flat with the first quarter as we continue to focus on cash flow neutrality in our E&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. 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. We're on pace for a very solid 2018 as well. Back in May, we also announced our intentions to redeploy our second internal frac spread and to optimize our completion schedule around the inclusion of that second OWS fleet in addition to our third-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 third-party service providers in terms of capital costs and input elements. We look forward to starting operations of the second 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. We're 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 of 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 2015 and 2016, 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 and 2016. You can see that our overall hedge book has grown since May. We now have hedged about 65% of our oil volumes in the second half of 2017 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&P spend of about $200 million, which excludes infrastructure spend. Additionally, we expect to continue to be cash flow neutral on E&P spend in the second half of the year as we ramp up activity.
Our track record also speaks to our disciplined strategy and our focus on improving well 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 second 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 two weeks of the month. During our last call, we signaled that we would come in relatively flat to 1Q for the second quarter. In fact, we came in just a little under the mark. Breakups impacted the pace of completion activity in parts of April and 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 and June to work the backlog of wells offline back down.
We'd originally expected to be flat quarter-over-quarter, these two factors cost us around 1,000 to 1,500 BOEs per day. More recently, volumes were over 66,000 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 second 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, 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 is 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 continued to see a tightening of the market during the second quarter. The cost of a 4 million pound, 50-stage completion is now $6.5 million. The cost of a 10-million-pound, 50-stage completion currently runs $7.3 million.
We think inflation will continue to rise in the second half of the year, the pace may be slowing, as shown by the availability of more service options than what we saw in April and May. Our year-to-date CapEx is in line with our guidance, and we expect the remainder of 2017 E&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 the well performance improves. As Tommy mentioned, we continue to test bigger jobs, as well as stages per job, perf clusters and perf spacing, diverters, and other techniques to optimize our fracs. We now have a good sample of bigger jobs in Indian Hills, including two 20-million-pound tests, and are excited about the early time results.
We continue to test the upper bounds of proppant loading, in the last few days, we completed our first 30-million-pound well in Wild Basin. Also, we now have much more production data on our previous test in Wild Basin and have updated the charts on page five 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 this 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 3 3BX well in Wild Basin, 20-million-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 are 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. 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 and fairway areas for 2018.
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, its contribution to basin takeaway capacity is making a significant impact on basin-wide differentials. The line started moving oil in June, 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 first quarter to $3.50 in the second quarter, we saw only a partial impact in our second quarter differentials, we expect to see a more substantial impact to third quarter and beyond. Differentials in June were down to about $3 per barrel, 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-$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 takeaway has put significant pressure on basin-wide differentials, 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&T increased slightly this quarter, 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 it 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 2017. The team has done a great job maintaining the stellar efficiencies that we achieved over the last two 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 third quarter. 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. 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. We see it continuing to improve organically 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. To ask a question, you may press star then one on your telephone keypad. If you're using a speakerphone, please pick up your handset before pressing the keys. To withdraw your question, please press star then two. The first question comes from Neal Dingmann with SunTrust. Please go ahead.
Morning, guys. Say, 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 and 30-million-pound jobs. 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-pound jobs at this time?
Yeah. On just straight cadence, now we've got 28 for the first half of the year. It's kind of consistent with what we said in May. You get 48 for the second half of the year and kind of split it between the two quarters. 24 roughly in each of the last two quarters, and Taylor can give you some color around prop intensity on those.
As we said, we've got one 30-million-pound job and so far and have tested a number of the 20 millions. For the rest of the year, as Tommy said, we're going to do more wells and about
Roughly 60% of the whole program will be actually a little bit more than that, but around 60% be over the four-million-pound job, but still shooting to have a 10-million-pound average. We're just going to have a mix of different jobs to test the full range as the year goes on. The 30-million-pound job in terms of performance, it has just now come online. 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. Just one last follow-up, if I could. Could you talk about, again, that second spread? You did talk about the timing of that coming, but just talk about the size of that, and given what you're seeing now on 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.
You bet.
It'll come on here within the next two weeks or so. The two spreads will be the same size. We did the second spread, we laid it down last year in February. To bring it back, we actually added some horsepower to the spread. So as we talked about the commissioning, getting it back up and running, and at the same capacity and size as the first spread, will cost us roughly $15 million. All that'll really be in place when we bring it on here in a couple of weeks.
Thanks again, guys.
You bet. Thanks, Neal.
The next question comes from Brad Heffern with RBC. Please go ahead.
Morning, everyone.
Morning.
On the workovers for last quarter, was there any reason that you were seeing more need for that than expected? Was there anywhere that work was particularly concentrated?
The workovers really are a function of just winter and breakup. You can have more wells down in the winter period just because of operating conditions. Combining that with cycle times really being longer, you end up with more wells going down. Cycle times are just winter, days are shorter, harder to get as much work done in a day. It takes more equipment to get all those wells back on. We ended up getting a bit of a backlog that we really worked down in May and June. Once we got past breakup, got more rigs out there, and worked that backlog down. The fact is, you look in July, you really see the workover count start to come down. It's not a reflection of any particular area. It's kind of spread across the whole position.
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. Then secondly, can you talk at all about the cadence for OMS spending? It was kind of heavy this quarter.
You talking about which part of the spending? You talking about capital?
Yeah.
Yeah.
Yeah, capital.
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. 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 Gabelman with Goldman Sachs. Please go ahead.
Hi. Thanks for taking my question. Question on Wild Basin, the higher GOR there, was that expected? How do we think about that gas mix going forward?
Yeah. 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's closer to 85% oil and 15% gas. 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. 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.
The older vintage wells across the play are performing in terms of oil cut exactly or as you expected. Is that safe to say?
Yeah.
Yeah. They're pretty much performing as we would expect.
Great. A second one. Can you talk about the M&A environment in the Williston right now? Halcon, I think, surprised most of us to the upside on the print they got. I'm just wondering, are you guys more of a buyer or seller of assets in this market?
Yeah. I would say that it's consistent with what we've always done, 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, we'll do that. We continue to look for little things that are $1 million or $2 million here or there. Occasionally, something big like that, SM, will pop up, we're always looking to bolt on.
Okay. Last one, if I may. You mentioned if the commodity heads south, you could reduce activity. 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?
Yeah. It's consistent with what Michael said, what we've been saying for some time, is we're kind of managing this thing within a $45 to $55 band. As it starts to head to $40, we contract 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, the activity is an output of it. This year, we had 76 completions. In that world, we'd probably have somewhere in the range of 45 or 50. We'll see where that goes. Also keep in mind too, we're continuing to build our hedge book. What was it, Michael? 65% for the second half of this year, continuing to build the book.
We're only at 22,000 for 2018 right now, continuing to build that book next year to insulate us against that price. That's kind of how we're managing it, 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 KeyBank. Please go ahead.
Morning, guys. Thanks for taking my questions.
You bet.
Hey. Taylor, I was hoping, looking at the plots that you put up on Wild Basin, it looks like you're having more success with the 50 stages versus 36 in the 4 million-pound jobs. Is that sort of the base case now for that 4 million-pound job, is getting the tighter frac stage spacing there?
Yeah, David. We've actually gone to 50 stages on all the jobs, so both the 4 million pounds and the bigger jobs. We're seeing better well performance with the increased stages, and we think better distribution in the frac.
Got it. Your comments, I think, on the John 3 3BX earlier about that well being choked back early and how it's producing at 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're looking at the data and trying to analyze and see if there is a EUR or longer-term well performance benefit of choking 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, we don't have any conclusions at this point.
Good. I appreciate that. Just the last one, if I might. I think you mentioned that you're getting close to optimization for the program. I guess, can you 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?
Yeah. It really continues to evolve. What you've seen us do over the past year is we kind of have a base recipe that we're working off of. Right now, the average well is more like a 50-stage, 10-million-pound job. It's all sand, we're testing a lot of things around that to understand what's going to be the optimal job going forward. If we see something like going from 36 to 50 stages, it's clearly making an impact, we'll make a move and blend that into our standard job. It's going to continue to evolve as we go.
Yeah. David, in my comments, it's really focused around Wild Basin because that's where we have the most data. As we move to currently Indian Hills and Alger, recently up to Red Bank, 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. 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. Thanks, Tommy. Thanks, Taylor. Good luck, guys.
You bet. Thanks, David.
The next question comes from Ronald Mills with Johnson Rice & Company. Please go ahead.
Hey. Good morning. A couple questions.
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 and 2018 exit targets, have you factored in any incremental uplift from the use of higher intensity fracture? What are some of the assumptions behind that growth profile versus how you're completing wells?
Yeah, Ron, generally with the bigger jobs, we've factored in the benefits of doing them, but as you make a step up from a four to a 10 into a 20, it's on a percentage basis. Then we use a type curve. When you look at some of these, look on page five, 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. We're actually modeling them that way. We've got flat production for an extended period of time. Then you'll see them outperform, as that flat production continues.
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. 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 quarters, 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 second quarter?
Yeah. We're right on track with the math. If you looked at July, of course, being in the summer helps. It should be more consistent.
Yep, it'll be. Go ahead.
Okay. Well, I would 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 even 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?
As we've stepped out to the other areas, we've been testing these bigger jobs as well. As I mentioned, we've got, for example, in Indian Hills, we've got a couple of 20-million-pound frac jobs. 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 planned as well, so the 20-million-pound fracs, those will be done this quarter. We'll When I say done, we'll get them fracked, get them on production. Meaningful production data is going to be on that Red Bank stuff probably late this year, early next year.
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-million-pound job for a 10,000-foot lateral. Great results on it so far. As we drill further south, right now we're in the Spratley unit. Again, going to test a range of bigger jobs there as well. 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, we'll work on optimizing those jobs further. 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?
Yeah, that's a 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. It could impact an area around it based on the results that we see. On top of that, you've got a number of wells which we're tracking by other operators. There's quite a few that are in the extended core and even in the fairway that are being tested with 1,000, 2,000 or more pounds per foot of proppant. We'll track those and talk about those as we get more data. 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? 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.
Yeah. The differentials, as we talked about, really have stemmed from a strategy that has gone back five or six 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-plus thousand barrels of takeaway capacity, a lot of long-term contracts associated with it. What it does is it brings a lot of demand for us as producers in the basin. One of the things that our marketing team did a great job of is really 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.
We're in a situation where there's a lot of takeaway capacity in the basin with much lower production levels. That's good for producers, and it tightens our differentials, especially given that we're 85% short-term on our oil barrels, we can actually move our barrels to the best price at any given time. It gives us the chance to get very tight differentials, and you've seen that in our results.
All right. Thank you.
Great. Thanks.
This concludes our question and answer session. I would like to turn the conference back over to Tommy Nusz for any closing remarks.
Great. Thanks, Phil. We're looking forward to the second half of 2017 as we nearly double our completion activity from the year-to-date levels. The next six months represent the heart of the 2017 program, and more importantly, lay the groundwork for everything to come in 2018 and 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.