Chord Energy Corp (CHRD) 2013 Q1 法說會逐字稿

Good morning, my name is Regina, and I will be your conference operator today. At this time I would like to welcome everyone to the first quarter 2013 earning 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.

(Operator Instructions)

I would like to turn call over to Michael Lou, Oasis Petroleum's CFO, to begin the conference. Thank you. Mr. Lou, you may begin your conference.

Thank you, Regina. Good morning, everyone. This is Michael Lou. We are reporting our first quarter 2013 results and we are delighted to have you on our call. I'm joined today by Tommy Nusz 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-K and our quarterly reports on form 10-Q. We disclaim any obligation to update these forward-looking statements.

During this conference call we will also make references to adjusted EBITDA, which is a non-GAAP financial measure. Reconciliations to adjusted EBITDA to the applicable GAAP measure can be found in our earnings release or on our website. I will now turn over the call to Tommy.

Good morning. In line with our past calls, I will lead off with general comments. Taylor will provide an operational update with some of the key items we are focused on this year, and Michael will finish with a few financial highlights. I would like to start by saying I'm definitely proud of the team for what they've accomplished the last three 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 2011 and 2012 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.

Let me expand on three key areas of our business that drive our value proposition. First, back in 2011, we experienced one 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 first quarter of this year, as we delivered production above the top end of our rage at 31,153 BOEs per day. We also raised our full year production guidance range to 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.

Second, over the last year we have overcome massive cost inflation by lowering weighted average operated well costs from about $10.5 million in the first half of 2012 to $8.4 million in the first quarter of 2013, and we are well on our way to achieving our $8 million goal by the end of this year. The $8.4 million in the first quarter of 2013 and the year-end target of $8.0 million are before savings from OWS. Including the impact of OWS, our well costs were $8.1 million across our operated program for the first quarter of 2013. The right way to think about modeling our average cost to drilling 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 are in good shape on our drilling and completion budget as we exit the first quarter, 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 first quarter working interest improvements. So, we were on track to spend $111 million less on drilling and completion Cap Ex in 2013 compared to 2012, while completing about 106 net wells in both years.

And lastly, in the midst of significant volume growth in 2011 and 2012, 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 salt water disposal side, about 55% of our salt water flows on our own pipes to our own disposal wells and an additional 20% is trucked to our own disposal wells. We are off to a very good start and hope to be able to carry that momentum through the rest of the year. With that, I will turn the call over to Taylor.

Thanks, Tommy. Two 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 in pad operations that falls out of the sub-surface 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 whereby leaving reserves behind by drilling too few. Our work on this front will then lead to best practices for pad development by fitting the sub-surface to the surface.

To evaluate the sub-surface and inner well spacing, we are utilizing three important methods. Inner well spacing pilot tests, extensional drilling in the first 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 in-fill density patterns. Early results of the 2012 spacing test suggest that four 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 returns per spacing unit. This year we have 22 in-fill pilots spread across the acreage position which will test well spacing of up to six wells per formation, implying up to 12 wells per DSU for 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.

Second, the 2012 three-fourths extensional program was very successful with stepout wells in north Cottonwood, east and middle Red Bank and in Montana, with results similar to Bakken wells and their respective areas. Based on these encouraging results, we have scheduled 15 extensional and stepout 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 first quarter of 2013, we cored through the lower benches of the Three Forks and performed enhanced log analysis for the six 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 first well in a lower bench late this year or early next year.

As we are testing the sub-surface spacing, we are simultaneously working on surface well arrangements. We were drilling 60% to 70% of our wells this year on multi-well drilling pads. We have 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 costs by 5% to 10% through operational efficiencies, shared services and centralization of tank batteries. With the data we're gathering this year on the sub-surface, we should be set up for optimum spacing as we shift 80% plus pad development in 2014. We are making great progress on this front. With that, I will 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 have ever delivered, resulting in oil and gas revenues of $242 million in the first quarter. Differentials were just 1% in the first quarter, down slightly from 1.5% in the fourth quarter of 2012, as we continue to move substantially all of our volumes on rail to the premium price 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 second quarter. 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 of our third-party-owned crude gathering system, which has multiple marketing options.

During the first quarter of 2013, we formed Oasis Mid-Stream Services, a wholly-owned subsidiary to hold our SWD infrastructure and other mid-stream assets and give us optionality in the future. With the formation of OMS in the first quarter, we made the appropriate prospective changes to the way the financial statements are presented. Therefore, we now have revenue and operating expenses for OMS which are related to third party working interest owner volumes. Historically, revenue from third parties was an offset to our LOE but it is now presented in OMS revenue. Additionally, we now charge a portion of our G&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&A and depreciation due to OMS allocations, and all of this taken together is essentially EBITDA neutral.

We reported LOE in the first quarter 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 up by $0.50 per BOE to $6.25 to $7.50 per BOE. We have also lowered the top end of our G&A guidance from $85 million to $82 million, 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 $1.4 billion 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 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 will turn over the call to Regina to open the lines up for questions.

(Operator Instructions)

First question will come from the line of Dave Kistler of Simmons & Company.

Real quickly, very impressive on the well cost savings coming from, call it $8.8 million in '12 down to about $8.1 million when you factor everything in, or $8.2 million. Obviously 8% to 10% savings. You talked about at the start of the year going from 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 of that together in terms of where costs are going from here? Obviously, it seems like you are going to continue to ramp those down and probably fall under $8 million throughout the year.

Yes, Dave, so this is Taylor. We made a big jump here early in the year and are well on our way to our target at year end, and we continue to hold that target at $8 million. But based on where we stand, like you mentioned, we are more optimistic we may be able to do better than that.

Okay. And maybe switching over a little bit, you outlined at the beginning of your comments what you guys have done on the infrastructure build-out with respect to gathering on gas, on oil, on salt water 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? Trying to think back competitively as you fill out your portfolio through the balance of the year. Does that put you in an advantaged position as a prospective buyer?

I think it does, Dave. And it's not so much in the middle of the basin, but as you move out toward 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 the infrastructure. We got that oil system in. 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 third party on gas and oil or the internal on salt water.

Okay, appreciate that. Then one last one, with the creation of OMS, liquidity is in great shape. So, if this vehicle that is 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, the possibility of spinning that out that we could see accelerated activity from you guys at some point?

I think it 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 a very strong balance sheet, a lot of liquidity. It's nothing that is 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 from Ladenburg Thalmann.

Good morning. Just a couple of things. Looking at the working interest that you picked up around your areas, I just want to get a sense of roughly what the cost was of those.

Are you talking about just the increase in our interest, 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 first quarter, our average working interest, if you just do the math, it looks to be 86% average working interest. Now, we knew that the first quarter was going to be a little bit higher on average just because of the well make up of the wells that we are completing there. So, our budget initially was around 79% in the first quarter. So, you had an uplift of 7% working interest across those wells. Now, that comes in.

There is a pick up of some of the acreage that we will just buy in, some of it we'll swap into, some of it, a little bit of it will be non-consents. It's a mixture of things. Our average acreage cost, it tends to be about $1,000 an acre on average throughout the program last year. That's holds through this year. So, that gives you a bit of feel on cost of those working interest increases.

Great. And talking about acreage out there in general, I guess I 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 guess I'd call it dormant acreage as acreage that just requires really tough land work or unusually uncooperative land holders? I'm trying to get a sense of, in your existing footprint, if we look out a little longer term, do you view the chance of picking up more acres as being pretty good or pretty much, it's a done deal, not much left?

We think that we will be able to continue to build our acreage position and it's really, like Tommy suggested, not really the core of the 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 in the infrastructure we have in place, we have some advantages that have allowed us to build the position. Takes a lot of work. Anything from guys that can whole lease currently to other people that -- operators that hold the production and/or the acreage that we'll buy. So, we are just continuing to try to build that position and we think we will do it. Not necessarily gigantic chunks, but in pieces that will build up over time.

Great. I just had one thing on the income statement from the quarter. Sorry if 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 are completing. You might have some more wells that are completed that have lower prop-in 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 third party piece. So, in this case, if you look at the 86% average working interest, what shows up in our income statement's only the 14% of the work that they do that is 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 it's just third party. That's it for me. Thanks.

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 rational to form OMS and what you're seeing in the basin right now on salt water disposal trends that, that subsidiary might be able to capitalize on.

Ryan, good question. On OMS, once again, it's more about optionality for us. We have now a fairly large system on the salt water disposal side, specifically, that we have been investing in over the last couple of years and we will continue to invest in. We have got a system across most of our acreage 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 leverage that system right now, we just 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 the third 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, so there is a third party component to it. But you are right. Is there an ability to bring in third party operated wells on to the system? That is certainly a possibility. We are not going there right now, but that's certainly a possibility for the future.

Okay. And then a quick modeling question. G&A came in pretty low in the quarter. Less than $14 million. So, I was just wondering if there is downside potential to that guidance of $75 million to $82 million and if you could just walk us through the assumptions there.

Yes. No, it's a good question. There is a couple of pieces there. The $75 million to $85 million, the old range, we did lower the top end because we came in a little bit lighter in the first quarter. There is an impact as we formed OMS, now a portion of our G&A actually gets allocated to OMS. It gets wrapped up into that allocation, so we will only show a smaller portion which allows our total G&A to come down a little bit. But we feel pretty good about that new range that we just put out.

Okay, thanks. I will hop back into the queue.

Your next question comes from the line of Subash Chandra with Jefferies.

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 have done already. Like, I would expect you might see all saturations, thicknesses, frac patterns et cetera. If you could comment on that. And then second, the -- where are the verticals placed over how wide an area, if you could talk to it. Thanks.

We -- the location of the pilots range across our acres positions. We had -- have them in the east side in north Cottonwood, in middle and south Cottonwood. We have two of them that are -- or actually one right now in Indian Hills. We had an existing one that was already in Indian Hills and then one in Red Bank and one in Hebron. They cover across the whole position.

As far as results, we have the cores, we have done visual inspection. There is -- 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 -- match up with the log analysis to confirm and make sure that what we are seeing on logs is accurate. We are -- I'd just say that we are encouraged by what we have seen for sure in the first bench, it's present across the position, and our results in the first bench continue to support that. The second bench present across the position and looks like it may have a appreciable saturation.

The thing that all this work is focused on is the thin bed -- imbedded nature as you go into the Three Forks, and we are definitely seeing that. We are picking up more porosity and potentially oil saturation than you would otherwise see if you just add standard logs. That all we can say about it right now. Like I said, we are encouraged. It's going to take us at least half the year to get -- to start to get -- in half year, by the summer time, 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 will probably pick some places to test the lower benches.

Okay, and this program was also designed to pick up third and fourth benches, et cetera, right?

Yes. It's actually, we cored all the way through the sections, so through all of the benches in the Three Forks.

Okay, and one more from me. Are there any other extensional TFF completions since the April presentation update?

No. The latest ones were the ones that we've previously talked about.

Okay. Thank you.

Thanks.

Your next question comes from the line of Irene Haas with Wunderlich.

This is Mo sitting for Irene. Just a quick question on the oil price. How do you feel about the Bakken differential going forward?

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 second quarter.

Overall in the basin, given the amount of takeaway capacity in the basin which is now well over the current production levels, feel pretty good that the differential is called capped out a bit. So, a lot of it is 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. As that narrows, our differential in the basin gets a little bit wider, and that's what you have seen here recently. But overall, we feel on a very good position differential-wise that we won't see the $20-plus differential blowout that we saw in the early part of last year, which was mainly because of a very constrained takeaway capacity market. Given than you have a lot of capacity now, you shouldn't see those big blowouts in the basin going forward.

Very helpful. Thank you.

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

Good morning, guys. Thank you 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. I thought you said earlier that you are seeing encouraging data that you think it's prolific across of your acreage. I guess, could you give a little color around that? And at what point or how much time do you think you would need before you'd include those locations in primary inventory?

So, the 110,000 acres that you are talking about is based on the wells that were tested 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. We talked about them a little bit in the third and fourth quarter. The results on those wells, they look like the Bakken wells that are around them, so they are economic. One is the Mercedes well which is middle Red Bank, and another one is the Justice well, which is in Montana and the Hebron block. Both of those wells look to be economic.

Then -- and so based on that, and then also the north Cottonwood well we drilled last year, the Zdenek, we just include a very small area around it as being within primary. But the rock, the sub surface from that down to the south Cottonwood area looks very consistent. And so as we drill out additional tests in that north Cottonwood area and then the west Red Bank and the Montana areas, this year we just, based on all of the data we have, we are encouraged that you are going to see that economic area in the Three Forks significantly expand and probably cover most of our acreage. But we still got to get the data and confirm that. That's our early indications.

Sure, thank you. And my last question is just on the well costs that 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 contracts is coming in lower, because obviously, it's before the impact of OWS. And then as you look out to '14, would it be unreasonable to assume another 10% reduction in cost is unreasonable?

On the first question for the $400,000, I see we've gone from the $8.8 million to the $8.4 million, that was really a combination of some savings on the service side. But probably lesser amount in terms of percentage than we saw last year, maybe in the 25% range of that savings and then really the rest of it through efficiencies. 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 cost and you are going to see that as the year continues it's more on the efficiency side where you are going to drive the cost down. And then as you go into 2014, we think we will continue to get more efficient and bring the cost down but probably not in as large a chunk. 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 from Peregrine Investment.

Good morning, guys. Can you talk about the long-term plans for the mid-stream segment? Do you think it ultimately ends up being monetized or in the MLP structure, or do you think that will stay internal long-term?

I think we are very early on in that. Right now, we are still focused on growing that salt water disposal system to make sure that we touch our whole acreage position and making sure that we can keep up with the production levels with our disposal capacity. We are 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 in our systems that we have with third parties right now. So, right now, we were operating it. We are 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 Tameron with Wells Fargo.

Hi, morning. Can you guys talk a little bit about the step-out's that you mentioned during the prepared remarks, some of the stuff that you are doing, and can you just give us more color on that? Step-out's into Montana, some of the Missouri stuff.

Okay. So you're talking about the Three Forks? The Three Forks, we've got 15 wells scheduled that are outside of what a we've called the primary de-risk Three Forks, and those wells will be, again, spread across the position. There's probably, I don't have the exact numbers, but on the order of five or so in north Cottonwood. And then you have 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 two or three quarters, three or four quarters? How should we think about that?

Correct, it's going to be spread -- some of that -- some of those wells are on pads where you are 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've 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 have talked about before, they spend and have continued to spend, actually it's probably gone up a bit. We used to talk about it as, 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 is these little add-on things that we look at all the time, and some of them take time. Some of these things we'll work for a year before we get them done. But we have been keeping them busy on the Williston stuff.

Okay. All right, final question. When you run the math, guidance looks conservative for the full year. Any comment on that?

I think consistent with what we have done in the past, we try to approach it from one direction, not overshooting and come back and adjust that back down. So, I think we will do that again this year.

All right, that's helpful. Thanks. I appreciate it.

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

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 first quarter?

Dan, on average we have got about 73%, 74% average working interest through the year. It was a little bit higher at that 79% level modeled in for the first quarter, and so it's a little bit lower through the rest of this year. Clearly, there are is possibly of a bit of upside of working interest side like we did last year and like we did in the first quarter, but it's difficult to quantify the impact. Going forward in our program, it's probably somewhere in that 70% to 75% average working interest throughout our position in future years.

Great, thanks. And as a follow-up, can you speak days spud to spud and spud to sales today and what it looks like going forward and at recognizing the impact from pad drilling?

Yes. 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 first quarter, but that was due to all the pilot holes that we drilled, which is -- had to drill vertically all the way through the section, plug back and then kick off, so it just added days to wells. We are optimistic, we will continue to drive that down. There is a point of diminishing returns that at some point where it's tough to get that further, but we think we will push it down some more this year. As you go to pad, 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 five to eight day process to rig down, move to the next wall and spud, it's more like a day to skid the rig and get over the new hole and get back to drilling.

But as think of spud to spud, it used to be -- we used to call it like ten wells per rig per year because our spud to spuds were like 35 to 37 days. Whereas today, basically 12 wells per rig per year. If you think about that it's, at a high level, it's 30 days plus or minus spud to spud.

Right, got, 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 and the out periods.

You mean limit in terms of the activity that we can do?

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.

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 increased cycle times, whether it's spud to spud or spud to rig release. On spud to rig release, the best we have done so far is 15 days, but you are always going to have a bit of an outlier. Can we get from the 23 to 20? Maybe 18 if things are really going well. I don't know at this point going forward that you really are 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 are running about 90 days; and over the course of the last two years, it's -- at one point it got up to about 120 days. Now it's back in to 90 day range, 80 to 90 day range. I think the -- and keep in mind with these pads, you're kind of batching the works. 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 are in full pad development mode effectively -- now it's not this clean because of the way you have to batch the work on the wells. But you ought to be somewhere in the 65 to 75 day range spud to first production once everything hits in the full manufacturing mode.

And Dan, if the other part of your question is around pace of how many wells we are going to drill each year, this year we are drilling 128 and we are completing 128 wells. What you see in our presentation is that our inventory of operated wells, that's just over 2,000 operated wells, we say we have got a 14 year inventory. That is assuming about 145 well pace. So, that's a way you can 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 how we are 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 rate is a little bit higher than where we entered this year.

Great, thanks.

Your next question comes from the line of Eli Kantor with Iberia Campbell.

Good morning, guys. Was hoping you could touch on differences you see in well head economics across your acreage position. Looks like well productivity is a little bit more prolific towards the center part of the basin relative to your acreage. The west and to the north, wondering how much of the difference in well performance is offset by difference in well cost.

So, I'll highlight a couple of areas just to give you an idea what you are talking about. In the middle part of the basin, Indian Hills, deeper, we still used about 60% ceramic in our completions. Our well costs are higher there, a little over $9 million. And -- but very robust economics with recoveries on the wells in that area, which are 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. We are drilling and completing wells there just over the $7 million cost, probably around $7.2 million 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 robust as well. And then dependent where you are in the acreage position, we've got -- it varies cost and returns.

And you'd mentioned the recent $400,000 reduction you'd seen in well costs is at least partially related to a change in well design. Are you still testing different completion designs, or are you pretty much set with the different mixes of ceramic and sand that you're using at your acreage position?

We continue to optimize our completions, and we vary everything from [profit], like you are talking about. We continue to test higher percentages of sand as opposed to ceramic in a number of areas. In Red Bank, we've now done a number of fracs that are 100% sand, at 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 are also trying a number of different things as well. 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 of those things to try to really maximize the EURs in the wells and minimize the cost.

Great. Thanks, guys.

Your next question comes from the line of Peter Mahon with Dougherty.

Good morning, guys. Most of my questions have been answered, but I just had one. This has to do with your salt water disposal system. 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 been stagnant for the last quarter or two. 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 the LOE cost that you've talked about in the past?

Yes. The salt water disposal system continues to progress pretty nicely. Now, realize that as we are growing this, we are trying to keep up with the growth in production that we are seeing on the oil side as well. Although the percentages don't move as dramatically as maybe you'd like to see, you are moving pretty rapidly in terms of drilling new salt water 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 a ballpark range that you're going to get to.

You are always going to have a piece of your business that is trucked to third 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. We will always probably use a component of truck costs -- truck on a salt water disposal system.

Okay, great. Thanks a lot, guys. That's all I had.

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

Good morning, gentlemen. I was curious, looking over Montana, there is 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 fringed Montana acreage. Do you see any potential -- other potential zones outside of the Bakken or Three Forks out there?

Really across the whole position. We were interested in other objectives. We just have 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 Three Forks. But high degree of focus on those two producing formations, and then we will 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 is somewhat misunderstood. But if you are kind of north of that Elm Coulee trend and south of the Brockton-Froid 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 are doing in this core part of the Bakken. But all of our acreage, even in Montana, looks kind of like what we are doing in North Dakota.

Great, and then just out of curiosity, on the wells that were completed in Q1, what were the percentage that were completed on pads?

That's a smaller number than -- if we talk about 60% to 70% on the year, we don't have that exact number in front of us, but it is a smaller number at the beginning part of the year, and most of the pad work is towards the back half of the year.

Great. Thank you so much.

Thanks.

And at that 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 operators in the Williston Basin. We have been able to deliver on expectations, drive down well costs, increase price realizations and expand our resource space. We are proud of the Oasis culture, the accomplishments of our team and the direction we are going as a Company. As always, thanks for everyone's precipitation 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.