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 Q2 2014 Earnings Release and Operations Update for Oasis Petroleum. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question and answer session.
I will now turn the call over to Michael Liu, Oasis' CFO, to begin the conference. Thank you. Mr. Liu, you may begin your conference.
Thank you, Ryan. Good morning, everyone. This is Michael Liu. Today, we are reporting our Q2 2014 results. We are delighted to have you on our call.
I'm joined by Tommy News 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 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 of 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 grown 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've 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 the 3rd 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 3 4th column across our position. While movement to full field development across our 5 100,000 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 2nd 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 breakup and has set us up to drive production growth in the second half of the year. We plan our rig and completion schedule in the Q2 to minimize rig moves during spring breakup, which naturally minimizes your ability to get wells completed.
Exiting breakup, we've increased the number of frac spreads from 3 to 6 and clean out crews from 4 to 7, which will support our increased pace of work. We continue to expect to complete about 60% of our full Muir 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 whole 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 2013 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 efficiencies, we've increased our walking or skittable 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 costs down to $7,300,000 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 $100,000,000 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 $1,250,000,000 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, proppant quantities, proppant type and delivery mechanisms to optimize our completions and deliver strong returns across our acreage position. Earlier this year, we discussed the move to 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 through increased fluid volumes or profit amounts. The biggest shift to date has been our move to slickwater completions. We are 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 3 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 £3,500,000 of profit. While it's still early, the results are encouraging as we design the plans for full field development with slickwater wells. Example of this is the White unit in Indian Hills, where we will test 7 slickwater wells through the 3rd bench of the Three Forks.
We expect production to begin in this unit in the late 3rd or early 4th 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 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 test, 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 3 times more sand than our base design. These wells will generally be completed with more than £9,000,000 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 We're especially excited about the Cornell well, which is in the Red Bank area.
Preliminary production for this 2nd bench well has been impressive, producing an average of 10.50 barrels of oil equivalent per day through the 1st 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 will be completed in the second half of the year. The inputs we have discussed, bad drilling, well cost 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 Q2. As we have stated in the past, OWS provides us a natural hedge against cost inflation in pressure pumping service as well as certain segments of the supply chain. In the first half of twenty fourteen, OWS saved us approximately $350,000 per well. And since inception, our first spread has returned 2.8 times our capital invested, so it has been a great investment for us. Our 2nd crew, which began operations in the 2nd quarter, has had a smooth start up and is currently operating 20 fourseven.
In addition, OWS also supplies about 2 thirds of the total profit 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 profit directly gives us an advantage on cost 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 at 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 in development. With respect to infrastructure, the consolidated blocks aid in the build out 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 and 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 at 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 pipeline additions will continue to add to an extremely strong takeaway environment in the Williston Basin. With a total pipeline capacity of nearly 1,600,000 barrels of oil per day, combined with forecasted rail capacity in 2016, takeaway capacity should easily surpass production growth, providing opportunities to maximize oil price realizations. We have 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 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 and 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 $1,400,000,000 of liquidity, which includes 1 point $5,000,000,000 of elected commitments on our $1,750,000,000 borrowing base.
Our debt to EBITDA is a comfortable 2.2 times debt to 2nd 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 the call over to Ryan to open the lines up for Q and A.
Your first question comes from the line of Drew Venker from Morgan Stanley. Your line is open.
Good morning, everyone. You completed less wells than planned in 2Q, 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 and the slick waters and larger completions are back loaded. So you're going to see more of the impact towards the end of the year, 3rd in Q3 and into the 4th quarter.
And so should we see 4th quarter production really accelerate from 3Q? I guess that's what 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 Q4 just like the Q3.
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. That's helpful. And then lastly on OWS, how much of your operated program will be covered by your pressure pumping fleet and say it's the second half of the year?
So second half of the year will 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. And that kind of swings because of wells on pads and the increased backlog of well completions like we're seeing at the end of the quarter, let's say 30 to 50 in general. Thanks.
Your next question comes from the line of Noel Parks from Ladenburg Thalmann. Your line is open. Good morning.
Good morning, Noel.
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 types. And you also talked 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 by coil. So it's just a different method of placing the proppant downhole.
Okay. Does that have much impact on the sort of incremental cost for those fracs?
So the in terms of cost, let's talk about slickwater and then a little bit about coiled tubing. So the slickwater fracs that we've done generally relative to our base design are $2,000,000 to 2,500,000 dollars 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 $2,000,000 more. So keep in mind the slickwater frac, we use at this point all ceramic proppant.
So the contrast where we continue to use 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 our base design all white sand and the contrast or increased cost of that completion is higher. So more like $2,500,000 to account for the move from sand to all ceramic.
Got you. And actually, Ed, as you continue in this transition of experimenting with the fracs and also expanding into a full field development, there was just a mention in the text about how that does add some variability just the transition to full 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're kind of getting close enough to whole field development where that won't quarter to quarter you won't see as much impact?
So are you talking about variability in terms of the well counts?
I guess, yes, just the pace of development share of the well counts.
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 of 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 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 5 times the well count. So we could get as high as 60 to 80. But in general, you're going 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 8 to 14 or 15 wells on a pad and now in some of these cases, in the Tufto 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, whether a well screening out on stimulation, whatever it is, it impacts 1 well. When you got 8, it impacts 8 wells. Sure. 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've 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 input pack should be muted. But in transition, it's going to make things a little bit more variable.
Thanks a lot. That's just what I was looking for. 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 tax net operating loss carryforwards and credits and so forth and sort of the outlook for cash taxes?
Yes. Right now, Noel, just 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.
And actually are the carry forwards still building at this part or are you working them down? I just thinking as you kind of have kept ramping up the drilling?
As you're ramping up drilling, your carry forwards are continuing to build.
Okay. Great. I think that's it
for me. Thanks a lot.
Thanks, Noel. Your next question comes from the line of Michael Rowe from TPH. Your line is open.
Hi, good morning.
Good morning.
I'm just wondering a couple of things. It looks like your completion backlog or your wells waiting 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 see 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 on how you see that trending in Q3 and Q4, that would be helpful.
So like we mentioned with the 16 rigs running, exiting the quarter at 67 and with all wells coming off 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 and the end of the year as we go into winter, which we normally do. So you're going to then see it ramp back up close to that 60 to 70 wells waiting on completion range at the end of the year. Okay.
And then just one more question on the new completions. You had a good slickwater result, it looks like there on in Montana for the middle Bakken, and you're seeing 35% production uplift. So I was kind of curious, how quickly do you all think at an incremental $2,000,000 per well that it would pay back the slickwater incremental investment on that side 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. And 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 cost 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 the cost down.
And 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 then 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 prices, 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 and similar to what our current wells are, which are kind of a 14 to 16 month payback. And that will be consistent and as we move down cost of the slickwater completions that could improve.
Okay, great. Thanks. I'll hop back in the queue.
Your next question comes from the line of Ryan O'Thun from SunTrust. Your line is open.
Hi, good morning.
Good morning.
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 will be built by a third party or do you plan to build that yourself?
Yes, Ryan, we've talked about that 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 3rd 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 discussed off of the acquisition, it would take probably 18 months to 24 months to put that infrastructure in place. So we have plans that we'll start drilling on that acreage kind of latter part of next year as that infrastructure gets in place.
And some 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 the tough tow wells.
Yes. And so we have done a little bit of drilling like economies talked about like on the rest of the acreage test the rock. So we're looking at taking cores and other subsurface measurement combined with some spacing test and really all the acquired blocks give us is giving 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 a drilling program on the acquired blocks starting in late 2015. All right, very helpful.
That's it for me. Thank you.
Thanks.
Your next question comes from the line of Dan McSpirit from BMO Capital Markets. Your line is open.
Thank you, folks. Good morning. Good morning. First question, could you discuss how the decline rate differs on the slickwater completed wells versus 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?
Yes. So far, we're not seeing a big difference in decline rate of the slickwater wells. We're seeing increased production In some of them, they actually have had a bit less of a decline profile. But generally, you can think of it as bumping up the overall type curve at a higher production rate. And 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.
Okay, 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 over that same period of time. So it's just for that 1st 45 days. The well in Red Bank, which is the Three Forks well, again, as compared to another nearby Three Forks well and 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 Tuff Tow and it's the Tuff Tow AT. T stands for 3 Forks and the well in Hebron is the Signal Butte 2B.
Thank you very much.
Welcome.
Your next question comes from the line of Michael Hall from Heikkinen Energy Advisors. Your line is open.
I guess just on the completions continuing on that. Given it sounds like quite a bit lower of a percentage of the first half wells are done using these various newer style jobs versus 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 then can you just remind me how you guys have factored these jobs into your prior guidance?
Yes. So we actually, Mike, we moved that 60% up to 70% of the total wells 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 at slickwater and about 5% of the remaining jobs will be larger volume fracs where we pump the 2 to 3 times the normal amount of sand that we do close to £10,000,000. 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. And that's going to come on in the Q4. So the overall impact of 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 4th quarter and beyond.
All right. That's helpful. Thanks. And then on the have you
done any jobs that are
a combination of the slickwater with higher sand loadings? I believe the slickwater already has some somewhat higher sand loadings as I recall, but with those higher loading jobs you're talking about, you combine the 2 or any plans to do that?
Yes. We haven't done that yet. We've the base design for us on slickwater right now is about 4 times the amount of fluid, but the proppant is actually 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 £3,500,000 to £4,000,000 of profit depending on where you are. In the slickwater design, it's about 250,000 barrels of fluid and again 3,500,000 to 4,000,000 pounds of proppant.
The big difference is that it's all ceramic in the slickwater job.
Got
it. And think about
is not quite on. Go ahead, sorry.
If you're trying to place £9,000,000 of the slickwater job, you're talking about 500,000 barrels. So that's a bit of a stretch.
Got it. Fair enough. And then how about cemented lines, plug in perps and increased per clusters per stage, have you kind of tested any of that or any plans
there? So we have tested cemented liners in the past. In fact, the slickwater jobs that we're doing are cemented liners. So they're one version of testing cemented liners. The perf clusters, 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 think that the submitted 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. Number 1, in the second quarter, given some of the road closures and things you talked about, was the mix of wells that were brought on more biased areas where you're not in full field development pad drilling, which I'm thinking would be more like Montana and North Cottonwood or maybe up in Red Bank or is that was that mix pretty typical of your annual mix in the Q2?
Yes. Yes. You hit on something that did occur. So a good way to think about it and why you get 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 fall over relative to where we thought we might be into the Q3.
The 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 and some of those other areas a little bit less in the deeper parts of the basin.
Okay. That's helpful. And then would that flip a little bit then as we think about the Q3? And then how many wells do you expect to turn on in the Q3?
Yes. So it should flip a little bit in 3Q. We 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 done in the first half and you can do the math, that's 81 well so far.
Yes.
Okay. That's helpful. Appreciate the color guys. Thanks.
Thanks.
Your next question comes from the line of David Tamarin from Wells Fargo. Your line is open.
Thanks. Good morning. Hey, David. 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 relative to these new wells, am I hearing it right that basically the curve shifts up just based on a higher IP, but you're not seeing any other change in the actual shape of the curve other than just shifting up. Is that the right way to think about it?
Yes. At this point, we don't think you we haven't overall on average observed a big change. I will say that early time some of these slickwater fracs because 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 it's pretty similar.
But that's what we've 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? Okay. And
if that's the case of whether it's slickwater or these big volume jobs, we've said that consistently is you just it's early days and you're trying to figure out is it 100% incremental recovery or is it 100% acceleration. And we just don't know that yet.
Yes. Okay. Somewhere Sorry, go ahead. Sorry. Sorry about that.
I guess most of the 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 in the production forecast. But how should we think about the P50? Is that a P50 number?
Is that a P75, P25? How should we think about the second half production ramp?
The 47 to 49 is a lot like what we would put out there. We gave a number for 2Q and we try to get a range that we're pretty confident we can hit, somewhere in that range. And so it's consistent with what we've done in the past. 2Q, we're at a little bit lower end of the range, but certainly within it. 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, just given the big ramp it looks like in the Q4?
No, at this point we just would tell you look at the 3Q number and then full year guidance we're going to be at 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 had anticipated post the acquisition? Or what I guess what's driving that number higher as well?
So really the 2 biggest drivers on our LOE at this point are the disposal cost and then also workover expense. At the time, we brought the new properties in. We also had a 3rd component that was higher, which is fixed cost. We've actually trended that down pretty nicely and started that in the range where we needed. The last two pieces that we need to work down is going to be the disposal piece and then the workover expense.
Workover expense typically tends to be up in the winter. 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 1Q and 2Q. We think that that will trend down in better weather for the second half of the year. The 3rd piece, which is the disposal component, Michael talked some about that, that it's going to take us a little longer to get the full disposal facilities in place.
And so while 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 really 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 $9,000,000 to $9,500,000 range by year end. And that's kind of how we got to our new full year guidance.
Okay. And so the workover 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 is it just kind of the winter the winter work over season that's running off?
Some of it is. We are experiencing a bit higher on the frac protect clean out business.
Okay.
The good news in that is, as we're going back into some of these wells that we the older wells we hadn't been in before, we need to find out if they're completely open all the way out to the end. 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 workover expense is going to be a bit higher. Just to make sure that the wells are cleaned out. And so I think it's probably is going to be a bit higher.
No, that's helpful. All right. Thanks, Tommy. Thanks, Taylor. You bet.
Your next question comes from the line of Ron Mills from Johnson Rice. Your line is open.
Hey, 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 plan number for the year. How do those look in terms of how are those weighted in the 3rd quarter versus the Q4?
In terms of when you talk about waiting, what do you mean?
In terms of how many if you have 120 or so wells left to complete to make up the remaining 60 percent of your completions for the year. How many of those will be in the Q3 versus the Q4?
You're going to have about 50 5% or so in 3Q and then about 45% of that is going to be in 4Q if things kind of work out. So actually should see a little bit bigger slug in the Q3. Like I said, we're going to work down these wells waiting on completion. And then kind of a buildup as we get back to year end, so a little lower percentage happening in 4Q.
Okay. And then on the cost of the enhanced completions, the slickwater, I think you talked about being $2,000,000 $2,500,000 higher. What's the relative impact if you on the wells where you're not using the slickwater, but you're increasing the proppant volumes by 2 to 3 times? And what's are you doing those increased proppant completions in 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 of doing those larger jobs is about $2,000,000 But in general, we think it'll be a little bit smaller than because it's just pumping more volume of all white sand, so maybe more like $1,500,000 to $2,000,000 But we've got jobs planned on the east side in Indian Hills and even in Montana. We've seen some data in Montana where we're pretty encouraged that you can work there as well. So across the position we're optimistic.
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?
Yes, 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 and 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.
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 one there's an existing Bakken well in that spacing unit 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 drill out.
And is that still really focused more on 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, still those areas.
Okay, great. And then Michael, one for you. You made a comment earlier about approaching free cash flow position is 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 in 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, etcetera, 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 earlier on infrastructure, are we going to use 3rd party, we're going to do some of it ourselves. But from just kind of the drilling or the E and P side of it, yes, I think we can get to cash flow neutral in 12 months.
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 the net benefit on the price uplift versus the increased cost?
Yes. 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've 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 percent 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 infrastructure.
Okay, great. Thank you so much.
Thanks, Rob.
Your next question comes from the line of David Deckelbaum from KeyBanc. Your line is open.
Thanks guys for taking my questions. Taylor, I don't want to make you any sort of beat the subject to death on the slickwater fracs. But I am 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?
Yes. You touched on one of the big drivers, the cost. And our plan was to make initial tests with all ceramic and then make a step to using a you can use a portion of ceramic and then sand and the next step would be all sand. And so the places that are shallow or the more distal parts of the basin like Montana will be the 1st place we'll 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 low 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, are you doing any of these jobs on any of the on and down spacing 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 NPV per section?
Sure. That's a good question. We've got all these recent results that we've talked about. So the TufCo, for example, is that 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 3rd bench and see what the performance looks like. It could result in a bigger stimulator rock volume and bigger drainage, which would then impact 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. Great. Your next question comes from the line of Dale Nicholson from KLR Group. Your line is open.
Good morning, gentlemen. Most of my questions have been asked, but just a point of clarification. The slickwater test that you guys did over Montana, you said that was on the western side of your acreage?
Correct. It's we've got a presentation that's updated and should be posted today. And if you look at it, 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 rock thins.
So, if it's effective in that, it just makes us feel even better about it going back to the west, I mean, back to the east.
Okay. And that
block is about 2 townships wide and it's on the western side of the western township.
Okay. 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 forming a little bit under below that expectation?
It's been. In fact, I think that's in one of the presentations that we put out that the average of the Hebron wells have been performing in line with that lower end of the type curve range or the 4.50 ish type curve.
Okay, perfect. Thanks.
Your next question comes from the line of Andrew Coleman from Raymond James. Your line is open.
Hey, great. Thanks for taking my questions. Looking at the slickwater jobs, I guess, building on some of David's questions here a couple of minutes ago, but how much more flowback are you seeing? And I guess from a cost side, I assume that that all goes in the OpEx budget when you put more water disposal, but I mean is that a meaningful adjustment?
So it's
you're right, most of that there is a portion that 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 disposal systems and disposal wells in place, it should not be significant impact on overall lease operating expense.
Okay, good. And then I'll think about it. Is there any bottlenecks in terms of water supply out there as you look to expand the use 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 Basin. It's an area where we're going to pick up and run 4 rigs starting late 2015, early 2016. And 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 pipe at or near our location, so we can really keep our costs down.
Okay. And is there an opportunity, I mean, it's probably to use produced water or is this stuff to saline the kind of use in the frac?
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. It's something we're looking at.
Okay, Great. Thank you.
Thanks. 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 twenty fourteen. Thanks for participating on the call today.