Morning. My name is Regina, and I will be your conference operator today. At this time, I would like to welcome everyone to the Q1 2013 Earnings Release and Operations I would now turn the call over to Michael Liu, Oasis Petroleum's CFO to begin the conference. Thank you. Mr.
Liu, you may begin your conference.
Thank you, Regina. Good morning, everyone. This is Michael Liu. We are reporting our Q1 2013 results and we're delighted to have you on our call. I'm joined today by Tommy News and Taylor Reid as well as other members of our 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 our quarterly reports on Form 10 Q. We disclaim any obligation to update these forward looking statements. During this conference call, we will also make references to adjusted EBITDA, which is a non GAAP financial measure.
Reconciliations to adjusted EBITDA to the applicable GAAP measure can be found in our earnings release or on our website. I'll now turn over the call to Tommy.
Good morning. In line with our past calls, I'll lead off with some general comments, Taylor will provide an operational update with some of the key items we're focused on this year, and Michael will finish with a few financial highlights. I'd like to start by saying that I'm definitely proud of the team for what they've accomplished over the last 3 years and in the last 12 months in particular. Oasis has been an amazing growth story as we have doubled year over year production in 20112012, while executing in an environment that has had plenty of challenges. Yet the team has continued to rise to the occasion and that has set us up for continued long term growth without sacrificing capital efficiency.
So let me expand on 3 key areas of our business that drive our value proposition. First, back in 2011, we experienced 1 of the toughest winters on record. Subsequently, we put in infrastructure, modified logistics and adjusted our planning processes to help mitigate the impact of such conditions. Our efforts paid off in the Q1 of this year as we delivered production above the top end of our range at 30,153 BOEs per day. We also raised our full year production guidance range 31,000 to 34,000 BOEs per day, implying we plan to achieve 44% annual year over year growth at the midpoint of our guidance range.
2nd, over the last year, we have overcome massive cost inflation by lowering weighted average operated well cost from about $10,500,000 in the first half of twenty twelve to $8,400,000 in the Q1 of 20 13. And we are well on our way to achieving our $8,000,000 goal by the end of this year. The $8,400,000 in the Q1 of 13 and the year end target of $8,000,000 are before savings from OWS. Including the impact of OWS, our well costs were $8,100,000 across our operated program for the Q1 of 2013. So the right way to think about modeling our average cost to drill and complete wells going forward would be to include the $300,000 reduction attributable to OWS.
The team has been able to drive well costs down by lowering third party service costs, improving efficiencies and continuing to optimize completion design. As a result, we're in good shape on our drilling and completion budget as we exit the Q1, even as we delivered more gross operated wells and a few more net operated wells to production than what we had originally planned based on increases in working interest in the operated wells. We still plan on completing 128 gross operated wells this year, but it looks like we can add about 2.4 net wells to our forecast of net wells completed during 2013 based on our Q1 working interest improvements. So we're on track to spend $111,000,000 less on drilling and completion CapEx in 2013 compared to 2012, while completing about 106 net wells in both years. And lastly, in the midst of significant volume growth in 20112012, we have established the necessary infrastructure to allow us to optimize EBITDA by both increasing our net realized prices and lowering our cost structure.
We now have approximately 90% of our operated wells connected to natural gas gathering infrastructure and approximately 85% of our gross operated oil volumes flow on pipeline. On the saltwater disposal side, about 55% of our saltwater flows on our own pipes to our own disposal wells and an additional 20% is trucked to our own disposal wells. So we're off to a very good start and hope to be able to carry that momentum through the rest of the year. With that, I'll turn the call over to Taylor.
Thanks, Tommy. 2 key items that we are focused on that will have a big impact over the long term are a firm understanding of inner well spacing as we go to full development and the optimal surface arrangement and pad operations that falls out of the subsurface well density. As we have stated previously, an early understanding of the reservoir will promote optimal well spacing and prevent over capitalization by drilling too many wells in a spacing unit or by leaving reserves behind by drilling too few. Our work on this front will then lead to best practices for pad development by fitting the subsurface to the surface. To evaluate the subsurface and inner well spacing, we are utilizing 3 important methods: inner well spacing pilot test, extensional drilling in the 1st bench of the Three Forks and analysis of the lower Three Forks benches through coring and high resolution logs.
First, many of our wells this year will be testing the limits of the infill density patterns. Early results of the 2012 spacing test suggest that 4 wells per reservoir appear economic with little interference between wells. EURs for the wells in these pilots were in line with other wells in the area. As we drill wells closer together in 2013, we are seeking to achieve the ideal spacing that maximizes the returns per spacing unit. This year, we have 22 infill pilots spread across the acreage position, which will test well spacing of up to 6 wells per formation implying up to 12 wells per DSU the Bakken and First Bench of the Three Forks combined.
We should have some preliminary results of these tests near the end of the year. 2nd, the 2012 Three Forks extensional program was very successful with step out wells in North Cottonwood, East and Middle Red Bank and in Montana with results similar to Bakken wells in their respective areas. Based on these encouraging results, we have scheduled 15 extensional and step out tests across the position in 2013. We think that there is a high probability that the Three Forks is economic across most of our acreage position and we will have more well results to share as we approach year end. Lastly, in the Q1 of 2013, we cored through the lower benches of the Three Forks and performed enhanced log analysis for the 6 pilot wells that were scheduled for this year.
We are early in the process of analyzing the data, so we will let you know more as we draw conclusions. Based on what we see, we will likely drill our 1st well in a lower bench late this year or early next year. As we are testing the subsurface spacing, we are simultaneously working on surface well arrangements. We are drilling 60% to 70% of our wells this year on multi well drilling pads. We've improved on the pad designs used in 2012 and are working on surface well configurations and battery designs that should enhance our pad operations as we transition into 2014.
Our current design should allow us to drive down cost by 5% to 10% through operational efficiencies, shared services and centralization of tank batteries. With the data we're gathering this year on the subsurface, we should be set up for optimum spacing as we shift to 80 plus percent pad development in 2014. We are making great progress on this front. With that, I'll turn it over to Michael to discuss the financial highlights.
Thanks, Taylor. We had another record quarter with production north of 30,000 BOE per day and the tightest differentials we've ever delivered, resulting in oil and gas revenues of $242,000,000 in the first quarter. Differentials were just 1% in the first quarter, down slightly from 1.5% in the Q4 of 2012. As we continue to move substantially all of our volumes on rail to the premium priced coastal markets. As you know, the differential between WTI and Brent has narrowed more recently, so we are expecting our differentials to widen out a bit in the Q2.
In fact, as our marketing team works has worked May sales, they were able to add back some pipe into the mix, putting about 25% of our volumes on pipeline. As we move forward, we will continue to optimize realized prices through leveraging the prices of our 3rd party owned crude gathering system, which has multiple marketing options. During the Q1 of 2013, we formed Oasis Midstream Services, a wholly owned subsidiary to hold our SWD infrastructure and other midstream assets and give us optionality in the future. With the formation of OMS in the Q1, we made the appropriate perspective changes to the way the financial statements are presented. Therefore, we now have revenue and operating expenses for OMS, which are related to 3rd party working interest owner volumes.
Historically, revenue from 3rd parties was an offset to our LOE, but it is now presented in OMS revenue. Additionally, we now charge a portion of our G and A and depreciation, which is associated with our operated volumes transported by OMS to LOE. These changes resulted in higher revenue due to recognition of OMS third party revenue, higher OpEx due to higher third party OMS OpEx, lower G and A and depreciation due to OMS allocations and all of this taken together is essentially EBITDA neutral. We reported LOE in the Q1 of $7.18 per BOE. Had we not formed OMS, LOE would have been $6.58 per BOE, which was in line with our guidance range.
Based on the new presentation, we adjusted our annual LOE range by $0.50 per BOE to $6.25 to $7.50 per BOE. We have also lowered the top end of our G and A guidance from $85,000,000 to $82,000,000 and a portion of the reduction is associated with the new presentation of OMS. Obviously, there are a few moving parts here, but the end result is the formation of the formation of OMS gives us optionality in the future. With the cash on hand and our recently increased borrowing base, we have approximately $1,400,000,000 of liquidity. Additionally, we layered into additional hedges in the quarter in order to protect our drilling program and cash flows.
We currently have approximately 22,000 barrels of oil per day hedged in 2013 with floors and swaps just around $91 per barrel on average and took 13,000 barrels of oil per day hedged in 2014 with approximately $91 per barrel floors and swaps on average as well. Another great quarter for our company, starting the year strong with excellent execution through the winter months, which sets the stage for a great 2013. With that, we'll turn over the call to Regina to open the lines up for questions.
And our first question will come from the line of Dave Kinstler with Simmons and Company.
Good morning, guys.
Good morning, Dave.
Real quickly, very impressive on the well cost savings coming from call it 8.8 percent in 2012 down to about 8.1 percent when you factor everything in or 8.2 percent. Obviously, 8% to 10% savings you first talked about at the start of the year going from kind of a 5% to 10% savings goal? And then Taylor made in his comments the possibility of 5% to 10% savings associated with the pad configurations. How do we put all that together in terms of where costs are going from here? Obviously, it seems like you're going to continue to ramp those down and probably fall under $8,000,000 throughout the
year? Dave, you want to touch on that?
Yes, Dave. So this is Taylor. We obviously made a big jump here early in the year and we're well on our way to our target at year end and we continue to hold that target at $8,000,000 But based on where we stand, like you've mentioned, we're optimistic we may be able to do better than that.
Okay. Okay. And maybe switching over a little bit, you kind of outlined at the beginning of your comments what you guys have done on the infrastructure build out with respect to gathering on gas and oil, on saltwater gathering disposal. When you think about those assets that are now in place, does that strategically put you guys in a better position as acreage within that infrastructure area may expire in terms of your ability to purchase it and be a cost advantage purchaser of that acreage going forward? Just trying to think about competitively as you fill out your portfolio through the balance of the year, does that put you in an advantage position as a prospective buyer?
Yes, I think it does, Dave. And it's not so much in the middle of the basin, but as you move out towards the edges where things get to be a bit more cost sensitive. It's a practical matter in a lot of these areas, especially in the central part of the basin, everything is pretty well held. But for instance, at the end of last year, we did a fairly sizable deal over on the northern part of North Cottonwood. And some of that driven by our ability to execute as well as impending infrastructure.
We got that oil system in fact, it just came on here a month or so ago. So I think those things do give us an advantage, whether it's the 3rd party on gas and oil or the internal on saltwater.
Okay. Appreciate that. And then one last one. With the creation of OMS, liquidity is in great shape. So is this a vehicle that's designed to give us more transparency with respect to cost in that side of the business and actually revenues and EBITDA on that side of the business?
Or is it being set up as something to be spun out over time? And should we read anything into the fact that with plenty of liquidity possibility of spinning that out that we could see accelerated activity from you guys at some point?
Yes. I think on the OMS side Dave that we formed it just to give us optionality in the future. Like you said, we don't have a need for that liquidity currently. We have very strong balance sheet, a lot of liquidity. So it's nothing that is a near term thing for us necessarily, but just gives us options going forward.
Great. Appreciate the color guys. Great work on the quarter.
Thanks, Dave.
Your next question will come from the line of Noel Parks with Ladenburg Thalmann.
Good morning.
Good morning, Noel.
Just a couple of things.
Looking at the working interest that you picked up around your areas, I just wondered can you give us a sense of roughly what the cost was of those?
Are you talking about just the increase in our interest in our existing wells or additions to our acreage position?
Well, I meant the existing, but if you could give a little detail on any other additions that would be great too.
So in the Q1, our average working interest, if you just kind of do the math, looks about 86% average working interest. Now we knew that the Q1 was going to be a little bit higher on average just because of the well makeup of the wells that we were completing there. So our budget initially was around 79% in the Q1. So you had an uplift of 7% working interest across those wells. Now that comes in.
There is kind of a pickup on some of the acreage that we'll just buy in. Some of it we'll kind of swap into, some of it a little bit of it will be nonconsent. So it's kind of a mixture of things. Our average So that gives you a So that gives you a bit of a feel on cost of those working interest increases.
Great. And talking about acreage out there in general, I guess I just wonder, I'm sure pretty much the low hanging fruit has clearly been picked up and leased. Is there around your properties any significant, I don't know, I guess I call it dormant acreage, this acreage that just requires really tough land work or just unusually sort of uncooperative landholders. So I guess I'm just trying to get a sense of in your existing footprint. If we look out a little longer term, do have the chance of picking up more acreages being pretty good or pretty much it's a done deal, not much left?
We think that we'll be able to continue to build our acreage positions really like Tommy suggested not really the core middle of the basin that's highly competitive. It's out a little bit more on the edges where we've with our cost structure and the infrastructure we have in place, we have some advantages that allowed us to build a position. It takes a lot of work. Anything from guys that could hold leases currently to other people that operators that hold the production and or the acreage that will buy. So we're just continue to try to build that position and we think we'll do it.
Not necessarily gigantic chunks, but in pieces that will build up over time.
Great. And just had one thing on the income statement from the quarter. Sorry, you mentioned this before. I noticed that the well services expense line was I think sequentially lower than the prior period. I just wondered if there was any new trend there?
That's just a combination of things of the type of wells that you're completing. So you might have some more wells that are completed that have lower proppant costs or the type of mix is important and then the working interest side is important. So remember when we report that OWS line item, it's only our 3rd party piece. So in this case, if you look at the 86% average working interest, what shows up in our income statements only the 14% of the work that they do that's not for our own wells or our own working interest position. So it can be higher or lower in any given quarter based on those factors.
Thanks for
the reminder. I did lose sight of the fact that that's just 3rd party. That's it for me. Thanks.
Great. Thank you.
Your next question will come from the line of Ryan Oatman with SunTrust.
Hi, good morning. Solid results guys. I was wondering if you could talk about the rationale to form OMS and what you're seeing in the basin right now on saltwater disposal trends that that subsidiary might be able to capitalize on?
Yes, Ryan, good question. On OMS, once again, it's more about optionality for us. We have now a fairly large system on the saltwater disposal side that continues that continues to be built out. So right now it's forming the subsidiary really just to put the assets in there to provide optionality in the future in case we want to do something with it. Nothing that we have in mind near term.
But if you can kind of leverage that system, right now that we just kind of feel like it gives us most optionality and most transparency if we put it in a separate subsidiary.
Okay. And is there a chance to increase kind of the 3rd party use of that system as opposed to just keeping it more internal?
Yes. Right now, we only move water on our own operated wells. And so there is a 3rd party component to it. But you're right, is there an ability to bring in a third party a 3rd party operated wells onto the system? That's certainly a possibility.
We're not going there right now, but that's certainly a possibility for the future.
Okay. And then just a quick modeling question. G and A came in pretty low in the quarter, less than 14,000,000 dollars So I was just wondering if there's downside potential to that guidance of $75,000,000 to
$82,000,000 And if you could just walk us through kind of the assumptions there? Yes. No, it's a good question. There's a couple of pieces there. The $75,000,000 to 85 the old range, we did lower kind of the top end because we came in a little bit lighter in the Q1.
There is an impact as we formed OMS. Now a portion of our G and A actually gets allocated to OMS. It gets kind of wrapped up into that allocation. So we only show a smaller portion, which allows our total G and A to come down a little bit. But we feel pretty good about that new range that we just put out.
Okay, thanks. I'll hop back in the queue.
Yes, thanks.
Your next question comes from the line of Sebastien Tundra with Jefferies.
Yes. Hi. I know you said it was early on the lower benches, but I was curious if you could comment on some of the things that I think would be visible from the work you've done already like I would suspect you might see oil saturations, thicknesses, frac barriers, etcetera. If you can comment on that? And then second, sort of the where were the verticals placed over how wide an area, if you could talk to it?
Thanks.
Okay. So we the location of the pilots range across our acres position. So we had them in the east side in North Cottonwood and Middle and South Cottonwood. We have 2 of them that are actually one right now in Indian Hills. We had an existing one that was already in Indian Hills and then one in Bank and 1 in Heffebron.
So they cover across the whole position. As far as results, we have the cores. We've done visual inspection. There's the testing work is underway on the cores. So we don't have that data analyzed yet.
We do have log data, but it's important that we get the high resolution logs to match up on core I mean match up with the log analysis to confirm and make sure that what we're seeing on logs is accurate. We are I'd just say that we're encouraged by what we've seen for sure in the 1st bench, it's present across the position. And our results in the 1st bench continue to support that. The 2nd bench present across the position and looks like it may have appreciable saturation. The thing that all this work is focused on is the thin bed, thin bedded nature as you go into the Three Forks.
And we're definitely seeing that we're picking up more porosity and potentially oil saturation than you would otherwise see if you just had standard logs. And that's kind of all we can say about it right now. Like I said, we're encouraged. It's going to take us at least half a year to get to start to get in half year, I mean, by the summertime to start to get some of that core work back. And then as we integrate all that data, like I said, by year end, we'll probably pick some places to test the lower benches.
Okay. And this program was also designed to pick up also different floor inches etcetera, right?
Yes. It's actually record all the way through the section. So through the all the benches in the Three Forks.
Okay. And one more for me. Were there any other extensional TFS completions since the April presentation update?
No. The latest ones were the ones that we previously talked about.
Okay. Thank you.
Thanks.
Your next question comes from the line of Irene Haas with Wunderlich.
Hi, guys. This is Mos in for Irene. Just a quick question on the oil pricing. How do you feel about the Bakken differential going forward?
Yes. Differentials have been obviously extremely strong for the last couple of quarters. Like we said, it's gapping out here a little bit in the Q2. Overall in the basin, given the amount of takeaway capacity in the basin, which is now well over the current production levels, you feel pretty good that the differential is called capped out a bit. So a lot of it's going to be dependent upon the relationship between that coastal market price or call it Brent right now and WTI and what that differential looks like.
So as that narrows our differential in the basin gets a little bit wider And that's what you've seen here recently. But overall, we feel in a very good position differential wise that we won't see the $20 plus differential blowouts that we saw in the early part of last year, which was mainly because of a very constrained takeaway capacity market. So given that you have a lot of capacity now, you shouldn't see those big blowouts in the basin forward.
Very helpful. Thank you.
Your next question comes from the line of David Deckelbaum with KeyBanc.
Good morning, guys. Thanks for taking my questions.
Good morning, Dave.
My question is on the Three Forks primarily. I recall your primary locations are based on 110,000 net acres of your position. And I thought you said earlier that you're seeing encouraging data that you think it's prolific across all of your acreage. I guess, could you give a little bit of color around that? And at what point or how much time do you think you'd need before you'd include those locations in primary inventory?
Yes. So the 110,000 acres that you're talking about is based on the wells that were tested kind of through mid last year. And so there are a few wells outside of that area that we have data on. They were drilled last year, completed last year and we talked about them a little bit in the 3rd Q4. The results on those wells, they're like they look like the Bakken wells that are around them.
So they're economic. 1 is the Mercedes well, which is in Middle Red Bank. And another one is the Justice well, which is in Montana in the Hebron block. Both of those wells look to be economic. And then and so based on that and then also the North Cottonwood well we drilled last year, the Zadine, we just include a very small area around it as being within primary.
But the rock, the subsurface from that down to the South Cottonwood area looks very consistent. And so as we drill out additional test in that North Cottonwood area and then the West Red Bank in the Montana areas. This year, we just based on all the data we have, we're encouraged that you're going to see that economic area in the 3, 4 significantly expand and probably cover most of our acreage. But we still got to get the data and confirm all that's just our early indications.
Sure.
Thank you. And my last question is just on the well costs, you guys have done a great job just at least measuring expectations and coming in beneath cost now. How much of that $400,000 I guess how would you break that out in terms of efficiencies or bid prices on contract that's coming in lower because obviously it's before the impact of OW less? And then as you look out to 2014, would it be reasonable to assume that another 10% reduction in cost is unreasonable?
Yes. So on the first question, so the $400,000 I assume you're going from the $8,800,000 to the $8,400,000 That was really a combination of some savings on the service side, but probably a lesser amount in terms of percentage than we saw last year, maybe in the 25% to percent range of that savings and then really the rest of it through efficiency. So some of it a little bit of pad savings and then you got savings on well design and cycle times. Those would be the main components. So less service costs and you're going to see that as the year continues.
It's more on the efficiency side where you're going to drive the cost down. And then as you go into 2014, we think we'll continue to get more efficient and bring the cost down, but probably not as in larger chunks. I'd say where we stand right now, maybe it's more in the 5% range.
Great. Nice job guys. Thank you.
Thanks, David.
Your next question comes from the line of Mark McDowell with Peregrine Investments.
Hey, good morning guys. Can you talk about the long term plans for the midstream segment? Do you think it ultimately ends up being monetized or in an MLP structure? Or do you think that will stay internal long term?
Yes. I think we're very early on. Right now, Ramy, we're still focused on growing that saltwater disposal system to make sure that we kind of touch our whole acreage position and making sure that we can kind of keep up with the production levels with our disposal capacity. So, we're highly focused on making sure that that is an efficient system and it gets to the same point where the crude gathering and the gas gathering is on our systems that we have with 3rd parties right now. So right now, we're operating it.
We're putting it into the separate subsidiary to give us options in the future, but it's a bit early to figure out where we go with that.
Great. Thanks, guys. Thanks.
Your next question comes from the line of David Cameron with Wells Fargo.
Hi, morning. Can you guys talk a little bit about the step outs that you mentioned during the prepared remarks, some of the stuff you're doing? And can you just give us more color on that, step out into Montana, some of the Missouri stuff?
Okay. So are you talking about the Three Forks? So the Three Forks, we've got 15 wells scheduled that are outside of what we'd call the primary kind of derisked Three Forks. And those wells will be again spread across the position. There's probably I don't have the exact numbers on the order of 5 or so in North Cottonwood.
And then you've got additional wells in Middle in West Red Bank and then some additional wells in Montana. So that 15 kind of spread across that position outside of South Cottonwood, Indian Hills and East Red Bank.
And the timing is just going to be over the next 2 to 3 quarters, 3 to 4 quarters, how should we think about that?
Correct. It's going to be spread. Some of that is some of those wells are on pads where you're going to have a rig get on a pad and drill multiple wells, but it will be between now and end of the year.
Okay. And then Tommy in the past you talked about potentially you guys have a new ventures group that's looking for new areas. Any update you want to give us on that?
The guys, as we've talked about before, they spend and have continued to spend, actually it's probably gone up a bit. We used to talk about it is call it 60% to 65% of their time on the Bakken and then call it 15% of their time on Williston expansion. But and then the rest on other things, other Upper Rockies tight oil things. But as a practical matter, those guys have been spending recently probably 100% of their time on just the Williston stuff.
And it's
there are a couple of larger deals out there, but then there's these little add on things that we look at all the time. And some of them take time. I mean, some of these things will work for a year before we get them done. So but we've been keeping them busy on the Williston stuff.
Okay. All right. And then final question, when you run the math, guidance is conservative for the full year. Any comment on that?
I think consistent with what we've done in the past, we try to approach it from one direction, not overshoot and then come back and adjust it back down. So I think we'll do that again this year.
All right. That's helpful. Thanks.
Appreciate it. Thanks, David.
Your next question comes from the line of Dan McSpirit with BMO Capital.
Thank you, folks. Good morning. Can you sketch for us what working interest looks like say on average over the balance of the year and in the out years given the increase in the Q1?
Yes, Dan. On average, we've got about 73%, 74% average working interest through the year. It was a little bit higher at that 79% level model then for the Q1. And so it's a little bit lower kind of through the rest of this year. Clearly, there is possibility of a
bit of upside on the working interest side like we did last year
and like we did in the first Going forward in our program, it's probably somewhere in that Going forward in our program, it's probably somewhere in that 70% to 75% average working interest kind of throughout our position in future years.
Great. Thanks. And as a follow-up, can you speak today's spud to spud and spud to sales today and what it looks like going forward kind of recognizing the impact from pad drilling?
Yes. So days for spud to rig release is what we really track and we continue to be around 23 days right now. We had a little bit of a tick up and closer to 24 in the Q1, but that was due to all the pilot holes that we drilled, which is we had to drill vertically all the way through the section plug back and then kick off. So it just added days to the wells. So we're optimistic.
We will continue to drive that down. There's a point of diminishing returns at some point where it's tough to get that further, but we think we'll push it down some more this year. As you go to pads, that's going to help some as well. But the biggest help there really is on the move. So that's from releasing the rig and getting to the next one instead of that being a 5 to 8 day process to rig down, move to the next well in spud.
It's more like a day to skid the rig and get over the new hole and back to drilling.
But if you think about spud to spud, it used to be we used to call it like 10 wells per rig per year because our spud to spuds were like 35 to 37 days, whereas today, it's basically 12 wells per rig per year. So if you think about that, at a high level, it's kind of 30 days plus or minus from spud to spud.
Right. Got it. Thanks. Appreciate the before and after there. And as a follow-up to that, as you move deeper into development mode, where operations become more maybe of an exercise in throughput, how does the pace of drilling wells change?
And with the completions knowing that there are certain physical limits or opportunities exist? That's maybe more of a theoretical question, but just asking just the same in an effort to get a better handle on the growth profile, not next quarter, but really in the out years, in the out periods.
So you mean a limit in terms of the activity that we can do or?
Right, exactly. How do you think about that? Just again, just trying to get a better handle, better picture on the growth profile beyond 2013?
Yes. What I would say is at this point to really project meaningful reduction in the numbers that we just talked about, probably a bit difficult to plan on improved cycle times, whether it's spud to spud or spud to rig release. On spud to rig release, I mean, the best we've done so far is 15 days, but you're always going to have a bit of an outlier. But can we get from the 23 to 20 maybe 18 if things are really going well. But I don't know at this point going forward that you're really going to see step changes.
The thing that tends to swing a bit more is the spud to first production for any number of reasons. When we IPOed, as I recall, Taylor, we were running about 90 days. And over the course of the last 2 years, it's at one point it got up to about 100 and 20 days. Now it's back in 90 day range, 80 to 90 day range. I think the and keep in mind, with these pads, you're kind of batching the work.
So it's going to be a bit choppy until you get everything working on pads and then everything will come back in line. And so that is one place where you should see once you're in full pad development mode effectively. Now it's not this clean just because the way you have batch the work on the wells, but you ought to be somewhere in the 65 day to 75 day range, but the first production. Once everything gets kind of in the full manufacturing mode. And then
Dan, if you could your other part of your question is around pace of how many wells we're going to drill each year. This year we're drilling 128, we're completing 128 wells. What you see in our presentation is that our inventory of operated wells at just over 2,000 operated wells, we kind of say we've got a 14 year inventory that's assuming about 145 well pace. And so that's a way you can kind of think about next year might be a little bit higher than this year. It may come through efficiencies.
It may come with because of another rig. But that's kind of how we're thinking about pace going forward is maybe a little bit faster than where we are this year. Right now, the plan is that we'd likely pick up a rig to get to that pace, so that our exit rates are a little bit higher than where we entered this year.
Great. Thanks. Great, Lee.
Your next question comes from the line of Eli Kantor with Iberia Capital.
Hey, good morning guys. I was hoping you could touch on differences you see in wellhead economics across your acreage position. It looks like well productivity is a little bit more prolific towards the center part of the basin relative to your acreage to the west and to the north. Wondering how much of the difference in well performance is offset by a difference in well costs?
So I'll highlight a couple of areas just to give you an idea what you're talking about. In the middle part of the basin, Indian Hills deeper, We still use about 60% ceramic in our completions. Our well costs are higher there, a little over $9,000,000 but very robust economics with recoveries on the wells in that area, which are kind of 650,000 barrel range
on average.
And then if you go to North Cottonwood,
you
see lower well recoveries more in the 450,000 barrel range, but well costs are significantly lower. So we're drilling and completing wells there just over the $7,000,000 cost, probably around 7.2 right now. And so the economics of those two areas are end up being pretty similar. Indian Hills maybe a little bit better, but North Cottonwood is pretty robust as well. And then depending on where you are in the acreage position, we've got it varies cost and returns.
And you had mentioned that the recent 400 $1,000 reduction you've seen in well costs was at least partially related to a change in well design. Are you still testing different completion designs? Are you pretty much set with the different mixes of ceramic and sand that you're using across your acreage position?
We continue to optimize our completions and we varied everything from proppant like you're talking about. So we continue to test higher percentages of sand as opposed to ceramic in a number of areas. So in Red Bank, we've now got a number of fracs that are 100 percent sand in Indian Hills. We've tested some wells with much higher percentage of sand closer to 70 as opposed to the current or the past amount being more like 40. But we're also trying a number of different things as well.
So the fluid that we pump, the viscosity of the fluid, the rate that we pump the fluid, size of the stages, number of stages. And so depending on where we are in the basin, optimizing all those things to try to really maximize the EURs in the wells and minimize the cost.
Okay, great. Thanks guys. Thanks.
Your next question comes from the line of Peter Mann with Dougherty.
Good morning guys. Most of my questions have been answered, but I just had one. This has to do with your saltwater disposal system. Hien Tsin, you talked about 55% of your water being running through your gathering lines as well as being deposited into your disposal wells. It seems like the progress on that system has kind of been stagnant for the last quarter or 2.
Can you talk about how that will evolve over the next couple of quarters? And how that might impact the timing of the $2 to $3 of savings in LOE costs that you've talked about in the past?
Yes. The saltwater disposal system continues to progress pretty nicely now. Realize that as we're growing this, we're trying to keep up with the growth in production that we're seeing on the oil side as well. So although the percentages don't move as dramatically as maybe you'd like to see that you are moving pretty rapidly in terms of drilling new saltwater disposal wells and putting in that system. That being said, we are moving towards where we can try to get about 70% to 75% of the volumes online.
Hopefully, a lot of that will be online before the year end. But that's kind of just a ballpark range that you're going to get to. You're always going to have a piece of your business that is truck to 3rd party wells. So we don't have the kind of the same goal of getting to 90% to 95% like we are on the gas side or the oil side in terms of gathering. So we'll always probably use a component of truck costs a truck on that saltwater disposal system.
Okay, great. Thanks a lot guys. That's all I
had. Thanks.
Your next question comes from the line of Gail Nicholson with KLR Group. Good morning, gentlemen. I was just kind of curious looking over Montana, there's some operators that are shooting seismic to locate some Red River potential. And I was curious if that's something that you might guys might consider doing on more of the Fringier Montana acreage? Have you seen any potential other potential zones outside of the Bakken or Three Forks out there?
Yes, really across the whole position, we're interested in other objectives. We've just been so focused on first the Bakken. It was really first big area of focus for us and then holding our land. And now we've shifted more to the 3 fourths, but a high degree of focus on those 2 producing formations and then we'll continue to look at the whole column both shallower and deeper as we go.
And one more thing to add on that Gail is that I think our Montana acreage is something that's somewhat misunderstood. But if you're kind of north of that Elm Coulee trend and south of the Brockton Freud fault, most of that looks like North Dakota for the most part. So there are certainly a lot of operators doing things that are in Montana that are outside of that area that we just talked about that looks a little different than what we're doing kind of in this core part of the Bakken. But all of our acreage in the even in Montana looks kind of like what we're doing in North Dakota.
Great. And then just out of curiosity,
That's a smaller number than this. If we talk about 60% of the year.
Okay, great. Thank you so much.
Thanks.
And at this time, there are no further questions. I will turn the conference back to Oasis for any closing remarks.
Thank you. Oasis continues to differentiate itself as one of the premier ops operators in the Williston Basin. We've been able to deliver on expectations, drive down well costs, increase price realizations and expand our space. We're proud of the Oasis culture, the accomplishments of our team and the direction we're going as a company. As always, thanks for everyone's participation in our call and in the continued support of our shareholder base.
Ladies and gentlemen, this does conclude today's conference. Thank you all for joining and you may now disconnect.