Chord Energy Corporation (CHRD) Q2 2014 Earnings Report, Transcript and Summary

Good morning, ladies and gentlemen, my name is Ryan, and I will be your conference operator today. At this time, I'd like to welcome everyone to the Second Quarter 2014 Earnings Release and Operations Update for Oasis Petroleum. [Operator Instructions] I will now turn the call over to Michael Lou, Oasis' CFO, to begin the conference. Thank you. Mr. Lou, you may begin your conference.

Thank you, Ryan. Good morning, everyone. This is Michael Lou. Today, we are reporting our second quarter 2014 results. We're delighted to have you on our call. I'm joined 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 also may 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. With that, I'll turn the call over to Tommy.

Good morning, and thank you for joining today's earnings call. We're very pleased to report another record quarter production with a volume of 43,700 BOEs per day and another quarter of delivering on our production guidance range. This translates into a production growth of 10% year-to-date when adjusted for our Sanish divestiture and we're set up for a very exciting second half. The basin has continued to grow and evolve on a number of fronts and Oasis continues to be a leader in operational improvement as we transform our company from holding drill blocks to a manufacturing resource development business. We have rapidly growing production while adding value in other areas of the business as well. We continue to optimize well costs, improve efficiencies and take control of key input elements in our business with OWS and OMS. Additionally, the team has added and integrated significant acreage positions in the heart of the play over the last 12 months. With the growth that we have experienced in overall resource potential, we've accelerated development from running 9 rigs in the first half of 2013 to 16 rigs operating today. We expect meaningful production growth through the end of the year and specifically in third quarter, increasing production to between 47,000 to 49,000 barrels of oil equivalent per day. We're currently focused on a couple of key areas that Taylor will provide more color on. First, our transition to full field development, and second, improvements in resource recovery through optimized completion designs and understanding of the prospectivity of the full Three Forks column across our position. While movement to full field development across our 500,000 acres does create some variability on a quarter-to-quarter basis, I'm extremely proud of the fact that our organization continues to do what we say we were going to do, delivering on our expectations. With that, I'll turn the call over to Taylor to provide more detail on what we're doing operationally.

Thanks, Tommy. The Oasis team continues to deliver on its production targets, growing production quarter-over-quarter by approximately 6% and over 10% on the year, excluding production from Sanish. We had some inclement weather that lead to numerous road closures in the second quarter, but conditions have now improved. During the quarter, we increased wells waiting on completion by 20 wells up to 67. This intentional rise in the well backlog helped us mitigate the impact of road closures during the spring break up and has set us up to drive production growth in the second half of the year. We planned our rig and completion scheduled in the second quarter to minimize rig moves during spring break up, which naturally minimizes your ability to get wells completed. Exiting breakup, we have increased the number of frac spreads from 3 to 6 and cleanout crews from 4 to 7, which will support our increased pace of work. We continue to expect to complete about 60% of our full year wells in the second half. As we mentioned last quarter, approximately 60% of our rigs are in full field development, where we are drilling out full spacing units. In contrast, the other 40% of our rigs are drilling partial spacing units as we confirm infill spacing density, test new completion techniques and hold land. This portion of the program is an investment in the future that will pay off with an increasing percentage of the program being dedicated to full field development as we move forward. Going to full field development results in an increase in the number of wells drilled on pads. We have trended from 45% of our wells on pads in early '13 to more than 90% of our wells currently on pads. We were able to spud more than 40 wells without moving a rig to a different pad during the quarter. To capitalize on pad drilling efficiency, we've increased our walking or skiddable rigs to 14 of 16 of our rigs compared to just 5 a year ago. Generally, these rigs can move to another well on the same pad within 12 hours compared to the multiple days it takes to move to a new pad. These efficiencies, combined with overall other operational improvements, have driven our base well cost down to $7.3 million, including OWS in the first half of the year. In fact, the full year impact of savings on our base well design translates into about $100 million, which has enabled us to absorb the higher costs associated with the enhanced completion designs without increasing our capital budget. We continue to expect to spend $1.25 billion on drilling and completion capital in 2014. Moving on to enhanced completion designs. Oasis has been on the leading edge in the basin to customize completions based on rock quality. We have tailored fluid types, profit quantities, profit type and delivery mechanisms to optimize our completions and deliver strong returns across our acreage position. Earlier this year, we discussed a move to a 60% of our completions with techniques different from our base design. Based on success since that time, we have increased the overall percentage to 70% and expect over 30% of the completions to employ techniques that significantly increase the size of the job, either to increase fluid volumes or profit amounts. The biggest shift to-date has been our move to slickwater completions. We were experiencing over a 35% uplift on average across our Bakken wells and have 2 additional results in Red Bank and Montana that we will discuss in a moment. Given these results, we have increased our planned slickwater jobs from 20% to 25% of our well count for the second half. Examples of slickwater success include preliminary results from our first Three Forks slickwater well completed in Red Bank. Cumulative production through 45 days has resulted in a greater than 35% production uplift compared to an offsetting Three Forks well, which was completed with our standard design for the area using cross-linked gel and 3.5 million pounds of proppant. While it's still early, the results are encouraging because we designed the plans for full field development with slickwater wells. An example of this is the White Unit in Indian Hills, where we'll test 7 slickwater well to the third bench of the Three Forks. We expect production to begin in this unit in the late third or early fourth quarter. In Montana, we completed the Signal Butte with slickwater, and it is producing 35% more than our Montana type curve. We are especially encouraged about this well since it is on the far west side of our Montana position. Because of the preliminary results here, we are moving forward with an additional -- with additional slickwater wells in this area during the remainder of the year. The increased production in the initial stage of a well's life is especially important in Montana where the tax structure is a bit more attractive than North Dakota. With these results, we have seen differential production uplift throughout most of West Williston. The one area we haven't tested is Painted Woods. However, given its location between our confirmed tests, it makes sense that it would likely work here as well. We will also test this technique on the east side of the basin during the second half of the year. We have also seen similar production uplift in the basin from increased sand frac jobs. And we're excited about its potential on our position. We expect to complete 7 to 10 wells across our acreage, with 2 to 3x more sand than our base design. These wells will generally be completed with more than 9 million pounds of sand with at least 36 stages. As we continue to refine our completion technology by area, we believe we can continue to improve economics across our position. Another item we have focused on this year is the lower benches of the Three Forks. In Indian Hills and South Cottonwood, the lower bench wells have continued to produce within or above our Three Forks type curve band and have the potential to add to our inventory. We're especially excited about the Cornell Well, which is in the Red Bank area. Preliminary production for this second bench well has been impressive, producing an average of 1,050 barrels of oil equivalent per day through the first 7 days. While it's still early time, it's another strong well at the top end of our Three Forks type curve band and should significantly expand our economic window for the lower benches north and west from the previous limit. To continue proving lower bench productivity, we have planned over 20 more wells that would be completed in the second half of the year. The inputs we have discussed, pad drilling, well costs and completion technology are all critical to resource development. As we have stated in the past, an important part of our strategy around cost control and production optimization lay in the stimulation segment of our business. In this segment, we saw some tightness in the availability of sand and completion services during the second quarter. As we have stated in the past, OWS provides us a natural hedge against cost inflation and pressure pumping services, as well as certain segments of the supply chain. In the first half of 2014, OWS saved us approximately $350,000 per well, and since inception, our first spread has returned 2.8x our capital invested, so it has been a great investment for us. Our second crew, which began operations in the second quarter has had a smooth startup and is currently operating 24/7. In addition, OWS also supplies about 2/3 of the total proppant pumped into Oasis operated wells and gives us the ability to do our work when the profit market gets a bit tight. This ability to source proppant directly gives us an advantage on costs, as well as transportation logistics and surety of supply. Before I hand the call over to Michael, I just want to say I am extremely proud of the Oasis team. Our people have worked hard to provide a lot of exciting opportunities that should enhance our business in the coming quarters.

Thanks, Taylor. Oasis has continued to deliver on the long-term objectives and key drivers of value to the organization, a critical one being the move to full field development. One key component to success of full field development is the infrastructure, especially given some of the recent regulations announced. Since our IPO, we have discussed the benefits of large contiguous operated blocks and the benefit of consolidated acreage positions and development. With respect to infrastructure, the consolidated blocks aid in the buildout as we can lay lines of pipe through multiple DSUs, creating one continuous system for our project areas. We have spent a lot of time investing heavily in partnering with third parties to develop our infrastructure since 2010. And what we have put in place has enhanced our returns through lower costs, higher cash margins and a higher gas capture rate. On the gas side, we currently have 96% of our wells connected to gas infrastructure. We have worked hard to connect wells and we are confident in our ability to meet the state regulations. In fact, we have had success in getting approvals under the new permitting regulations and are already in process of obtaining our 2015 drilling permits. With regard to oil, our gathering system collects approximately 75% of our produced oil, which has enabled us to deliver some of the best oil differentials in the basin to 8% for the quarter. The tight differentials are attributable to our ability to efficiently move crude between the pipe and rail markets in the basin. Recently, there have been a few significant announcements to add more than 800,000 barrels of oil per day of pipeline takeaway capacity out of the basin by 2016. The pipelines additions will continue to add to an extremely strong takeaway environment in the Williston Basin. With the total pipeline capacity of nearly 1.6 million barrels of oil per day, combined with forecasted rail capacity of -- in 2016, takeaway capacity should easily surpass production growth, providing opportunities to maximize oil price realizations. We've also been active in developing our own saltwater disposal business through OMS. We have approximately 52% of our water flowing through pipeline and 75% disposed into our wells. These percentages ticked down as you will recall with the acquisition, which has led in part to increased LOE. Additionally, LOE has trended up due to workovers coming out of the winter season and spring breakup. While per unit LOE costs have been higher than our historical average, we expect these to come down during the second half of the year. To account for these higher costs in the first half of the year, we have updated our full year range to $8.50 to $10 per BOE. One item I would like to point out is our consistently strong cash margins. The team has done a great job across the business from delivering the best possible oil realizations, the high percentage of our gas being sold, managing our G&A and operating costs, adding incremental revenue through OWS and OMS. And we are very pleased with our adjusted EBITDA margin, which was an impressive $64 per BOE. Finally, our balance sheet is in great shape. We have $1.4 billion of liquidity, which includes $1.5 billion of elected commitments on our $1.75 billion borrowing base. Our debt-to-EBITDA is a comfortable 2.2x debt to the second quarter annualized adjusted EBITDA, and we expect to continue to delever throughout the year as we get closer to cash flow breakeven. To protect our leverage, we added some hedges in the second -- in the quarter, increasing our 2015 position to on average 23,000 barrels of oil per day. We will continue to opportunistically layer on hedges as it makes sense to do so. With that, I'll turn this call over to Ryan to open the lines up for Q&A.

[Operator Instructions] Your first question comes from the line of Drew Venker from Morgan Stanley.

[indiscernible] pointed last fall, they'd be planning to queue, but you still delivered pretty solid volumes. Can you quantify how much those new completions have helped boost production?

Yes, Drew, at this point, we only have a few of those new completion techniques online, and actually, it's early days and a lot of that was post the quarter. So for 2Q, not a lot of impact. And as we've stated before, this program in the slickwaters and larger completions are backloaded. So you're going to see more of the impact towards the end of the year third -- in the third quarter and into the fourth quarter.

And so should we see fourth quarter production really accelerate from 3Q? I guess, that's what the guidance implies.

At this point, we're projecting to be 47 to 49 in 3Q, and when you look at the full year weighted towards the bottom end of our range.

But still, if you back -- I mean, if you just back into the numbers, it would imply another meaningful volume growth into the fourth quarter just like the third quarter.

Okay. And then just to clarify on the new completion techniques that the uplift you're seeing across the board is -- a pretty good average is 20% to 35%?

Yes, generally, it's -- most of it's around 35% or greater to this point.

Okay. And then, lastly, on OWS, how much of your operated program would be covered by your pressure pumping fleet in, say, the second half of the year?

So second half of the year, we'll probably on average run between 4 to 6 frac crews. And we've got 2, so it's going to be 30% to maybe as high as 50% of the activity at times. That kind of swings because of wells on pads and increased backlog of well completions like we're seeing at the end of the second quarter. But I'd say 30% to 50% in general.

Your next question comes from the line of Noel Parks from Ladenburg Thalmann. Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division: Just a few things. In listing the various contributing factors to improving the efficiency on the fracs, you listed off several fluid types and proppant. Can you also talk about delivery mechanism? Could you just elaborate a little bit on that.

So the delivery mechanism, just refers to coil tubing, for example. We've done some frac jobs where we are delivering it by coil. So it's just a different method of placing the proppant downhole. Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division: Okay. Does that have much impact on the, sorry, incremental costs for those fracs?

So the -- in terms of costs, let's talk about slickwater and then a little bit about coil tubing. So the slickwater fracs that we've done generally relative to our base design are $2 million to $2.5 million more expensive than our standard completion. It depends on where you are in the basin. So in the areas where we -- deeper parts of the basin where we still use ceramic proppant, the cost is about $2 million more. So keep in mind, the slickwater frac we used at this point, all ceramic proppant. So the contrast where we continue ceramic proppant is not as great as in areas where we use all sand. So in shallower parts of the basin, like in Montana, we use, on a base design, all white sand. And the contrast or an increased cost of that completion is higher to more like $2.5 million to account for the move from sand to all ceramic. Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division: And actually, as you continue in this transition of experimenting with the fracs and also expanding into full field development, there was just a mention in the text about how that does add some variability, just for the transition to fuel field development. And could you be a little more specific about kind of what you have in mind and whether there's much of that variability still ahead or whether we are kind of getting closer to full field development where that won't -- quarter-to-quarter, you won't see as much impact?

So are you talking about the variability in terms of the well counts? Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division: I guess, yes, just the pace of development [indiscernible].

Sure, yes. So just as you get a full field development especially as we go to a higher density of drilling on each spacing unit, you're going to get well pads that have more and more wells on them. And with that higher density drilling in each spacing unit, you're going to tend to have more of a lag in the time from when you spud on that unit to first production. Now the way we deal with that is we apply more rigs to do each of those spacing units to keep that cycle time down. But as compared to just drilling 1 or 2 or a small number of wells on a spacing unit to a larger volume, you're going to tend to see the time from the amount of wells waiting on completion could trend as high like this quarter, as high as 4 to 5x the well count. So it could get as high as 60 to 80. But in general, you got to see that work down and then come back up as you're drilling more wells on pads.

If you think about it, Noel, if you've got anywhere from to 8 to 14 and 15 wells on a pad and now on some of these cases, in the Tough Toe [ph] unit, we had 3 rigs running at the same time to try to manage cycle times, as Taylor talked about, but with, call it 8 wells, well, where in the past, if you were set back by whatever it is, weather, wells screening out on stimulation whatever it is, it impacts 1 well. When you got 8, it impacts 8 wells. Just because it tends to run more in series than in parallel. Now we offset some of that by running multiple rigs on a pad and those kinds of things, but it still sets you back. So if you've got some kind of hiccup or -- like I say on stimulation or road closures or something, you got a whole bunch of wells that get pushed back. And now over time, as you said, you get enough of it going and infrastructure in place that impact should be muted. But in transition, it's going to make things a little bit more variable. Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division: And I just had one more for Mike. On the -- as far as taxes go, could you just give sort of a rough idea of where you stand with your operating loss carryforwards and credits and so forth and sort of the outlook for cash taxes?

Yes, right now, Noel, with IDCs and whatnot, our cash taxes are pretty minimal. We do pay AMT taxes, but our cash taxes are actually -- continue to be fairly minimal and probably will be for the next 2 years or so. Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division: And actually, are the -- are carryforwards still building at this part or are you working them down? I'm just thinking as you kind of have kept ramping up the drilling.

As your ramping up drilling, your carryforwards are continuing to build.

Your next question comes from the line of Michael Rowe from TPH. Michael J. Rowe - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: I'm just wondering a couple of things. It looked like your completion backlog or your wells awaiting on completion backlog was about 67 at the end of Q2 versus 47 at Q1. Just given the size of your rig program, where do you all feel -- what do you feel like is a comfortable level for you all to have kind of in backlog and if you could just maybe discuss how you see that trending in Q3 and Q4 that'd be helpful.

So like we mentioned, with the 16 rigs running, exiting the quarter at 67 and with all the wells coming off or rigs coming off of pads, we expect in Q3 to work that number down. However, we're going to have a bunch of pad drilling again going into Q4, in the end of the year, as we go into winner, which we normally do. So you're going to density ramp back up close to 60 to 70 wells waiting on completion range at the end of the year. Michael J. Rowe - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Okay. And then just one more question on the new completions. You had good slickwater result looks like there in Montana for the Middle Bakken and then you're seeing 35% productions uplift. So I was kind of curious how quickly do you all think an incremental $2 million per well that it would pay back the slickwater incremental investment outside of the basin? And I guess just based on what you know now, do you feel like the economics of slickwater are better in the deeper parts of the basin and based on what you know today?

So it's really, really pretty early time. When we look at the Montana result, we're encouraged by what we're seeing early. And when you look at the cost increase, it's on par in terms of a percentage of costs relative to the base cost of those wells. So we feel like you're going to get a return that is at least as good as the existing wells with the current cost structure. We've got a good path, we think, of really bringing back cost down. If we continue to see that type of performance, the economics are going to be pretty compelling. As far as deeper parts of the basin versus areas like this that are further out from the center, we're seeing good results in both. And we've seen, like we said, on average about 35% uplift across the Bakken wells where we've collected data. And this well is really pretty similar to that. So we'll see how that pans out as we continue.

And Michael, on our returns, across the board, as you've seen in our presentation, that current oil price is where we get very strong returns from an IRR standpoint, 70% to 80% in that neighborhood. And so with slickwaters, as Taylor mentioned, if the economics are just the same, you're going to get those paybacks similar to what our current wells are, which are at a 14- to 16-month payback, and then, they'll be consistent. And as we move down cost of these water completions, that could improve.

Your next question comes from the line of line of Ryan Oatman from SunTrust.

Regarding the infrastructure, can you describe how you plan to attack the requisite gas gathering and oil transportation infrastructure on the recently acquired acreage? Do you think that'll be built by a third party or do you plan to build that yourself?

Yes, Ryan, we've talked about that. We're continuing to evaluate that. We should come out with a little bit more data towards the end of the year on which direction we're heading. But we're actually continuing to evaluate all different options. It may be a combination of using some third party and doing some of it ourselves, but we haven't decided all that fully yet.

Okay. And given that infrastructure is probably necessary before really attacking that acreage, when do you plan to shift to development mode on that acreage?

Yes, as we kind of discuss off of the acquisition, it would take probably 18 to 24 months to put that infrastructure in place, so we have plans that -- where we'll start drilling on that acreage kind of latter part of next year as that infrastructure gets in place.

And yes, on drill blocks that are going to be earlier. So it's not all going to be pushed out like the White Unit we just drilled at the Tough Toe [ph] wells.

Yes. And so we have done a little bit of drilling like Tommy's talked about to -- like on the rest of the acreage tests for rock, so we're looking at taking cores in other subsurface measurement combined with some spacing tests and really all the acquired blocks give us -- has given us the data to set us up for that full field development. Like Michael said, we'll have the full infrastructure in place so that we can take off on our drilling program on the acquired blocks starting in 2000 -- late 2015.

Your next question comes from the line of Dan McSpirit from BMO Capital Markets.

First question, could you discuss how the decline rate differs on the slickwater-completed wells versus those completed with the older method? And what does this mean for the company's base decline rate? That is, what is the base decline rate today and how is it expected to change, say, 12, 24 months from now?

So far, we're not seeing a big difference in decline rate. The slickwater wells, we're seeing an increased production. In some of them, they actually have less of a decline profile. But generally, you can think of it as bumping up the overall type curve at a higher production rate. So that's -- what we got to continue to watch is what does that decline profile look like out in time when you get 12 months out, 24 months out. So at this point, we don't have any guidance for you how -- we just say it wouldn't change the impact of the overall decline profile of the company.

Great. And as a follow-up, if I may. For how long have the slickwater Three Forks and Montana wells highlighted in the press release been online? And then, as a follow-up to that, I guess, could you -- to clarify, when you say 35% uplift, you're referring to initial production or ultimate recovery? And then, if you could just remind us of the names of those wells, again, the 2 wells that were highlighted in the press release.

Okay. So first in Montana, it's been on for about 45 days and the 35% uplift refers to production compared to the parent well in that area and so you -- over that same period of time. So it's just for that first 45 days. The well in Red Bank, which is the Three Forks well, again, as compared to another nearby Three Forks well, is for the period and it's been on production for about the same amount of time, a little more than 45 days.

And the names of those wells, I'm sorry.

So the well in East Red Bank is called the Tough Toe [ph] and it's the Tough Toe 8T [ph]. T stands for Three Forks. And the well in Chevron is the Signal Butte 2B.

Your next question comes from the line of Michael Hall from Heikkinen Energy Advisors.

I guess just on the completions continuing on that. Given it sounds like quite a bit lower of a percentage of the first half levels are done using these various newer style jobs versus the 60% total for the full year. Is it fair to assume then the back half of the year is quite a bit above that 60% level? And can you just remind me how you guys factored these jobs into your prior guidance?

Yes, so we actually, Mike, we moved the -- that 60% up to the 70% of the total well, and that is for the second half of the year. So that means 70% will be different than our base completion design. On the bigger volume jobs, it's a total of 30% and that breaks down to about 25% of the remaining completions for the year. Slickwater, about 5% of the remaining jobs will be larger volume fracs where we [indiscernible] the 2 to 3x the normal amount of sand that we do close to 2 million pounds. We've got a number of those that we've done recently and we're getting set up for a number of those that happen mid to later in 3Q and then even more into 4Q. A good example of that is that White Unit, which we're going to have 7 wells, all slickwater, pumped within the same spacing unit. That's going to come on in the fourth quarter. So the overall impact to the volumes, we think, you'll see some and we're factoring that in or trying to factor that in, and that's primarily going to be fourth quarter and beyond.

All right. And then, on the -- have you done any jobs that are a combination of the slickwater lists with the higher sand volumes? I believe slickwater already has somewhat higher sand volumes as I recall. But with those higher listing jobs you're talking about. Can you combine the 2 or any plans to do that?

We haven't done it yet. We've -- the base design for us on slickwater right now is about 4x the amount of fluid. But the proppant is actually the -- about the same as our base design. So it ends up being -- the base design is 60,000 to 70,000 barrels of fluid and 3.5 million to 4 million pounds of proppant depending on where you are in the slickwater design. It's about 250,000 barrels of fluid, and again, 3.5 million to 4 million pounds of proppant. The big difference is that it's all ceramic in the slickwater job.

If you're trying to place 9 million pounds of the slickwater job, you're talking about 500,000 barrels. So that's a bit of a stretch.

Got it and then how about some [indiscernible] talking first increased first clusters per stage, I mean, have you guys tested any of that or any plans to?

So we have tested cemented liners in the past. In fact, slickwater jobs that we're doing are cemented liners. So they're -- they're one version of testing cemented liners. The perf clusters we've -- we varied that depending on the job. In general, what we've seen between cemented liners and wells that are not cemented where we use light completion techniques, the results appear to be pretty similar. We don't know -- we don't think that the cemented liner by itself is differential. But for some applications like a slickwater frac job, it really makes sense because of the pressures and the rates that you're pumping.

Okay. And then I guess just jumping up to that -- kind of thinking about activity in the second quarter, given some of the road closures and things talked about. With the mix levels that were brought, more biased areas where you're not in full field development pad drilling, so I'm thinking it would be more like Montana and North Cottonwood or maybe up in Red Bank or is that mix pretty typical of your annual mix in the second quarter?

Yes, you hit on something that's -- [indiscernible] a good way to think about it and why you get to that performance or relationship is the deeper areas. You got a lot higher density in the wells that you drill per spacing unit. So we got on pads on those units and they're the ones that end up extending the most and they happen kind of to fall-over relative to where we thought we might be into the third quarter. Ones that we were able to get pulled up and completed were in those units that are more distal so like Hebron, North Cottonwood and some of those places. So we ended up having -- just like you said, a little higher well count in and some of those other areas a little bit less and the deeper parts of the basin.

Okay. And would that kind of flip a little bit then as we think about the third quarter? And then how many wells do you expect to turn on in the third quarter?

Yes, so it should flip a little bit in 3Q. We've got more wells like I said on passing those higher density units. I don't have a projected well completion number at this point. But like we said, we started with 67 wells waiting on completion. We're going to work that down in 3Q, and then when you look at the full year, we're going to have 60% of the total well count weighted towards the back half of the year. So 40% of the completions were down in the first half. And you can do the math that's 81 wells so far.

Your next question comes from the line of David Tameron from Wells Fargo.

Question, I think, I just want to clarify what -- the response to Dan McSpirit's question about the shape of the curve as far as [indiscernible] new wells. Am I hearing it right that basically the curve should shift up based on the higher IP but you're not seeing any other change in the actual shape of the curve shifting up, is that the right way to think about it?

Yes. At this point, we don't think -- we haven't overall in [indiscernible] observed a big change. I will say that early times, some of these slickwater fracs because of the amount of volume pump come on a little higher rate. So you can see a higher very early time decline. But overall, the curve once you come off that we think is pretty similar. But that's what we got to understand is what are these jobs going to do over the longer term, so you get 12 months 24 months out, what does that profile look like.

And that's the case of whether it's slickwater or these big volume jobs, we've said that consistently. It's just early days and you try to figure out is it -- 100% incremental recovery or is it 100% acceleration? And we just don't know that yet.

I guess most of my questions have been asked but just a couple more around the production guidance. And I think you guys have laid it out, but are there any big hurdles that need to happen for you guys to hit your second half numbers or assuming you get normal weather and you don't get a lot of downtime out in the field other than what you typically build into production forecast. But how should we think about the P50? Is that a P50 number? Is that P75, P25? How should we think about the second half production ramp?

The 47 to 49 is a lot like what we put out there. We gave a number for 2Q and we try to get a range that we're pretty confident we can hit it. Somewhere in that range and so it's consistent with what we've done in the past. 2Q were at the low bit -- lower end of the range, but certainly with that -- and we think we'll be able to do the same in 3Q.

Okay. Do you care to give us an exit rate for the year given just given the big ramp it looks like in the fourth quarter?

At this point, we just would tell you look at 3Q number. And then, for your guidance, we're going to be at the lower end of the range and you can do the math.

Okay. Last question and you might have addressed this and I might have missed it. But LOE, any reason it's been a little slower to come down than you'd anticipated post the acquisition or what -- or what's, I guess, what's driving that number higher as well?

So the really 2 biggest drivers on our LOE at this point are the disposal costs and then also workover expense. At the time, we brought the new properties in. We also had a third component that was higher which was fixed costs. We've actually trended that down pretty nicely and started that in the range where we needed. The last 2 pieces that we need to work down is going to be the disposal piece, and then, the workover expense. Workover expense, typically it tends to be up in the winter. You get a lot of wells when you get a really cold winter that go offline. More cost to do that work to get everything back on and we saw that, both in 1Q and 2Q. We think that, that will trend down in better weather for the second half of the year. The third piece which is the disposal component, Mike will talk some about that. That is going to take us a little longer to get the full disposal facilities in place. And so I'll -- we'll make some headway on that with some additional pipe and disposal wells in the ground this year. We won't get all the way where we want to be until a little more towards the end of 2015. So when you bake all that stuff together, it just takes time to work it down, but we feel good about the trajectory right now. And based on that, we're going to be, like we said in the past, we hope to be kind of more in the 9 to 950 range by year end, and that's kind of how we got to our new full year guidance.

Okay. And so the work-over expense isn't necessarily related to -- I mean, it's nothing different than typical field logistics. I mean, you're not doing -- you're not seeing more of that with older wells or -- is there anything -- is there any trend there or is that just kind of the winter work over season that's running off?

Some of it is. We are experiencing a bit higher on the frac protect cleanout business. The good news in that is, is we're going back into some of these wells that we -- the older wells we hadn't been in before. Find out if they're completely open all the way, all the way out to the, and so we have had a bit more of that. But I think just on a go-forward basis, I do think even long term our work over expense is going to be a bit higher. Just to make sure that the wells are cleaned out and I think it's probably is going to be a bit higher.

Your next question comes from the line of Ron Mills from Johnson Rice. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: Taylor, maybe just a little bit more clarity on the second half completions. You have another 120 or 125 completions probably to get to that planned number for the year. How do those look in terms of -- or how are those weighted in the third quarter versus the fourth quarter?

In terms of -- when you talk about weighting, what do you mean? Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: In terms of how many if you have 120 or so wells left to complete to make up the remaining 60% of your completions for the year, how many of those will be in the third quarter versus the fourth quarter?

You're going to have about 55% or so in 3Q and then about 45% of that is going to be in 4Q if things kind of workout. Actually, should see a little bit bigger slug in the third quarter. Like I said, we're going to work down these wells waiting on completion, and then kind of a build up as we get back to year-end. So a little lower percentage happening in 4Q. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: Okay. And then on the cost of the enhanced completions, the slickwater, I think, you talked about being $2 million, $2.5 million higher. What's the relative impact if you, on the wells, where you you're not using the slickwater, but increasing the proppant volumes by 2 to 3x. And what's -- are you doing those increased proppant completions in the areas where you don't think the slickwater is as applicable?

So we're actually going to try those increased volume jobs in a lot of places where we're doing the slickwater. The overall cost impact to doing those larger jobs is about $2 million. But in general, it's -- we think it'll be a little bit smaller than -- because it shifts pumping more volume of all white sand, so maybe more like $1.5 million to $2 million. But we've got jobs playing on the East side and in Indian Hills and even in Montana. We've seen some data in Montana where we're pretty encouraged that you could work there as well. Across the position, we're optimistic. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: In your release, you talked about slickwater maybe being more applicable across more of the position that you now have tests in Montana, Red Bank, Indian Hills. Is it fair to say that you think that the slickwater is going to be applicable across the majority of your acreage relative to what you thought maybe 3 months ago?

Ron, it's expanded quite a bit. And based on what we've seen to this point, we think, potentially, we could have uplift across most of it. The place that we're still pretty reserved is in Cottonwood, specifically North Cottonwood. So when you get above the area that we call Alger, all to the north there, we continue to pump a little smaller frac jobs to help control water cut. But we're going to test it in the South end. And if we see positive results, we'll march it more slowly. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: Okay. Great. And then in the white unit, you have the 7 slickwater tests. Are those spread across both the Bakken and the Three Forks? And is that the pad where you're going to drill 15 to 20 wells in total?

Yes, that pad, is actually, like I talked about earlier, since it's on the acquired acreage, it's infill spacing test and we're not drilling out the full spacing unit, it's just 7 wells. And it will have 1 -- there's an existing Bakken well in that spacing that is producing. We'll drill another Bakken well, 2 first bench wells, 2 second bench wells and 2 third bench wells. So we'll drill and then frac with slickwater across the whole section. And to your point about density, that's an area where you could have, we think, an order of 15 to 20 wells drilled in a full spacing unit drillout. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: And is that still really focused more in kind of the Indian Hills and South Cottonwood area where you think you end up with that kind of density, including the second and third benches?

Correct. At this point, it's still those areas. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: Great. And then, Michael, one for you. You made a comment earlier about approaching free cash flow position. In terms of relative timing, I think you've talked about getting there within the next 18 months or so. Is that still intact and does that assume similar activity levels and capital spending to this year? Or what are some of the inputs to that free cash flow positive comment?

Yes. It is similar, Ron. Obviously, we've accelerated pretty rapidly over here over the last 12 months. But with that level of activity going into next year, we should get to -- and given kind of current oil prices and differentials, et cetera, we should get to cash flow breakeven next year, sometime next year. So there are a lot of things that kind of depends on whether or not you keep the same level of activity. Some of those decisions that we talked about a little bit early on infrastructure, are we going to use third party, are we going to do it some of it ourselves. But from just kind of the drilling or the E&P side of it, yes, I think we can get to cash flow -- quick cash flow neutral in the next 12 months. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: Okay. And then on the pricing, you did have better pricing than most guys. You owe it to OMS in your comments. But if you think of the increased transportation costs versus the increased price realizations, how much was kind of a net benefit on the price uplift versus the increased costs?

Obviously, on our LOE side, we had slight increases to LOE costs, call it, $1 to $2 versus where we have been historically. The good thing is that the infrastructure side can move those cash margins in a bigger way. So I think our realizations are actually upwards of a couple of dollars better than some of the other players in the basin, and so having good solid infrastructure that gives you a lot of flexibility. We kind of said this a lot, but it gives us a lot of flexibility to move back and forth between pipe and rail and continuing to have that flexibility I think is a good thing. The other part of it is having 96% of our wells connected to gas infrastructure allows us to get that incremental gas revenue and remember that all drops to the bottom line, which is incredibly powerful for us from a cash margin standpoint. So we have been able to make up a lot of some of those smaller increase in costs on the LOE side with just much better realizations on the oil side and much higher sales on the gas side being connected to the infrastructure.

Your next question comes from the line of David Deckelbaum from KeyBanc.

Taylor, I don't want to make you sort of beat the subject to death on the slickwater fracs. But I'm curious on, as you guys think out into 2015 and testing this design, if you compare the costs and the uplift there, will you be testing jobs or intending to test jobs not using ceramics or using all sand at least in Montana? And how are you thinking about that in terms of being able to then drive a potential slickwater frac base completion down?

You touched on 1 of the big drivers of costs, and our plan was to make initial tests with all ceramic and then and make a step to using -- we can use a portion of ceramic and then sand and the next step would be all sand. And so the places that are shallower, the more distal parts of the basin like Montana, will be the first place will do that and then we'll work in towards the more central areas. The other place that we can make an impact is on the water side of the business. So both cost sources are important, and then, also the transportation, being on pipe as opposed to trucking can have a big impact. So those are really the 2 big pieces we'll be working on.

Okay. And are there any issues I guess near term getting the adequate number of pumps for all these slickwater jobs?

For us right now we haven't had any problem with that, and we're planning around it so we don't anticipate having a problem getting them pumped.

Okay. My last question is just the -- are you doing any of these jobs on any of the downspacing pilots? And I guess to follow that, if the returns by and large improve for all wells with an enhanced completion design, could that potentially cause you to rethink how many wells per section would be sort of a base case that would sort of improve that total MPV per section?

Sure. That's good question. We've got all these recent results that we've talked about, so the Tough Toe [ph] example is in a spacing unit where we drilled 8 wells and that was a Three Forks well. The rest of the fracs in that unit were more conventional. The Hebron well was in a spacing test. It wasn't a full spacing that was drilled, but it was 3 wells in proximity. And so we'll look at those results relative to the more conventional stimulations. And then the piece of data we want to capture on top of that is the White Unit, where we'll drill all 7 of those wells in spacing across the Bakken all the way to the third bench and see what the performance looks like. It could result in a bigger stimulated rock volume and bigger drainage, which would impact then the distance between wells and that's what we've got to figure out. Are you impacting more rock or are you just more effectively breaking up the rock in and around the well that we're stimulating. So I don't have that answer yet, that’s what we're focusing on.

Your next question comes from the line of Gail Nicholson from KLR Group.

Most of my questions have been asked, but just a point of clarification. The slickwater test that you guys did in -- over in Montana, you said that was on the western side of your acreage?

Correct. It's what -- we've got a presentation that's updated and should be posted today. And if you look at it, it'll -- it actually shows a map of where that well is and it's really on the western portion -- kind of northwestern portion of what we call the Hebron block. And so the point of that is, in general, as you head to the west, even within Montana, that package of rocks thins, so if it's effective in that, it just makes us feeling even better about it going back to the west -- I mean, back to the east.

That block is why -- and that -- that block's about 2 Townships wide, and it's on the western side of the Western Township.

And then from the standpoint of looking at that area, was that area performing on a non-slickwater basis performing in line with the 450 Mboe type curve over in Hebron or has it been performing a little bit under -- below that expectation?

In fact, I think that's in one of the presentations that we put out, that the -- the meet -- the average of the Hebron wells have been performing in line with that lower end of the type curve range of the 450-ish type curve.

Your next question comes from the line of Andrew Coleman from Raymond James. Andrew Coleman - Raymond James & Associates, Inc., Research Division: Looking at the slickwater jobs, I guess building on some of David's question a couple minutes ago. How much more flow back are you seeing? And I guess from a cost side, I assume that all goes into the OpEx budget. [indiscernible] water disposal but is that a meaningful adjustment?

So it's -- You're right. Most of that -- there is a portion on all these wells that we capture in capital, but it's pretty small. Overall, most of it does go into LOE but with our own disposals systems and disposal wells in place, it should not be significant impact on overall lease operating expense. Andrew Coleman - Raymond James & Associates, Inc., Research Division: Okay. And then, I'll [indiscernible] about it. Is there any -- are there any bottlenecks in terms of water supply out there as you look to expand the uses of slickwater across the acreage?

There are some areas that you got to really plan for to get the water in place. And so it's really important to get out in front. An example of that would be Wild [ph] basin, it's an area where we're going to pick up and run 4 rigs starting late '15, early '16. We're doing the work now to make sure that we can cost effectively get water in that area. You can always truck it but it would get super expensive. So we want to have piping in place. And in that case, we've got a couple of water providers that we're working with that will help us to get that water piped at or near our location. So we can really keep our cost down. Andrew Coleman - Raymond James & Associates, Inc., Research Division: Okay. And is there an opportunity -- there's probably -- do you just produce water? Or do you just use saline, the kind they use in the fracs?

Right now, it's -- we're just looking at it as fresh water. We've done tests with produced water. Since it's not cross-linked, it's easier to pump it. But we don't have immediate plans to do a slickwater job with produced water, but something we're looking at.

We have no further questions in the queue. I would now like to turn our call back over to Oasis Petroleum for closing remarks.

Great. Thanks, guys. The team has delivered on another great quarter. We remain excited about our ability to consistently execute against our plan, and look forward to an exciting second half of 2014. Thanks for participating on the call today.

This concludes today's conference call. You may now disconnect.