Chord Energy Corp (CHRD) 2013 Q3 法說會逐字稿

Good afternoon. My name is Tony and I will be your conference operator today. At this time I would like to welcome everyone to the third-quarter 2013 earnings release and operations update for Oasis Petroleum.

(Operator Instructions)

I will now turn the call over to Michael Lou, Oasis' CFO to begin the conference. Thank you. Mr. Lou, you may begin your conference.

Thank you, Tony. Good morning everyone. Today we are reporting our third-quarter 2013 results. We're delighted to have you on our call. I'm joined today by Tommy Nusz and Taylor Reid as well as other members of the team.

Please be advised that our remarks, including the answers to your questions, include statements that we believe to be forward-looking statements within the meaning of the Private Securities Litigation Reform Act. These forward-looking statements are subject to risks and uncertainties that could cause actual results to be materially different from those currently disclosed in our earnings release and conference call. Those risks include, among others, matters that we have described in our earnings release, as well as in our filings with the Securities and Exchange Commission, including our annual report on form 10-K and our quarterly reports on form 10-Q. We disclaim any obligation to update these forward looking statements.

During this conference call, we may also make references to adjusted EBITDA, which is a Non-GAAP financial measure. Reconciliations to adjusted EBITDA to the applicable GAAP measures can be found in our earnings release or on our website.

I will now turn the call over to Tommy.

Good morning, and thanks for joining us today.

It is been an exciting and important quarter and year for Oasis. We entered this year knowing it would be a transitional year, moving from acreage capture to acreage development and optimization. With our recent acquisitions totaling 161,000 net acres in the heart of the Basin, our year is now both transitional and transformational.

The team has continued to make progress on multiple fronts, including improving capital efficiency, further resource understanding through down spacing and lower bench work, and increasing value through acquisitions and acceleration. First, as we noted in the press release, well costs continue to move down across our position. Additionally, we have lowered spud to rig release down to 21 days in the third quarter. Our improved efficiency and optimization work has reduced total well cost to $8 million per well, before taking into account OWS, which lowers costs by another $500,000 per well.

Having hit our year-end 2013 target well cost of $8 million already, we continue to have confidence in our ability to get to $7.5 million by the year end 2014. Both of those numbers being before the effective OWS. Additionally, we now expect to hit our production targets for 2013 with $40 million to $60 million less in capital than our original $1.02 billion budget, even when we include capital for the 5 additional wells that will be completed on the acquired assets in the fourth quarter.

Second, we are more optimistic about the potential for inventory growth as we progress our down spacing efforts, doing more work on the lower benches of Three Forks. We have been encouraged by the results of the down spacing tests we have completed to date, and Taylor will cover that in a bit more detail momentarily.

Third, we are encouraged by our ability to capture additional resource through both acquisition and acceleration. Michael will give you an update on our acquisitions, but we continue to be excited about the opportunity to develop the 161,000 net acres that we acquired around the end of the quarter. All of the work we have done on our position is relevant to development of the what we just picked up. As we integrate the assets, capitalize on our capital efficiency and resource understanding, and grow our drillable inventory, we believe it is prudent to accelerate the rate of development across all of our almost 500,000 net acres.

Between the 11 Legacy Rigs, the 2 from the acquisition, and the incremental rig we just picked up, we're currently running 14 rigs. With the addition of the 2 rigs we expect to pick up in the back half of the year, we should exit 2014 with 16 rigs. With these rigs and the continued improvement in drilling days, it looks like we will be able to spud approximately 210 gross operated wells next year, of which approximately 80% to 90% will be on pads.

With that I will hand the call over to Taylor, who will discuss our operational results and some preliminary thoughts for 2014.

Thanks, Tommy.

The team delivered another great quarter. We completed 38 gross operated wells, with 29 of these wells, or 75% of the total, on pads. While the total completions came in a little light of expectation, we still came in just above the midpoint of our guidance range of 33,000 barrels equivalent per day. With the momentum of increased activity in the second half, combined with our recent additions from acquisitions, we are projecting fourth-quarter production to be between 42,000 and 46,000 barrels equivalent per day.

We are currently producing 13 of the 22 spacing tests planned for 2013. Early production from these well tests has been positive, with wells performing in line with wells previously drilled in their respective areas. Early production data, coupled with our modeling work is suggesting that it will take more than four wells per Horizon to drain the middle Bakken and first bench of the Three Forks in many areas of the basin. We will give more color around our plans as we roll out our 2014 program in January, but it is safe to say that the bias on well density is up from our current standard of 4 x 4. We even have a few DSUs that will test as many as 15 to 20 wells in a spacing unit, with 5 to 6 wells across each of the Bakken and lower bench intervals.

Additionally, preliminary testing and core work indicate there is a significant amount of resource in the second and third bench of the Three Forks across parts of our acreage. In Indian Hills we have two second-bench tests currently on production, the Patsy and Paul S wells. In one third bench, the [Omelette] online as well. All three wells look similar to first bench wells in the area. The Patsy, Polas, and Omelette produced 784, 712, and 804 barrels equivalent per day, respectively, during the first 30 days of production.

The Bonita well in North Cottonwood, a second bench test, is not yet completed, but will be online in the fourth quarter. We are also currently drilling at third bench test in South Cottonwood that includes a core through the full Bakken and three Forks section. In the next two quarters alone, we plan to drill an additional 15 lower bench wells. And as we look to 2014 we expect the overall program to be pretty evenly balanced between Bakken and Three Forks wells.

The transition of pad development has been remarkable and continues to progress. As I mentioned, we drilled 75% of our wells on pads in Q3, but that will increase to 80% to 90% in 2014. Recent advancements include an 8-well pad, where we executed simultaneous operations for the first time. The team put up some great results with spud rig release averaging 19.2 days and frac days averaging 2.6 days per well. The first well that we drilled in the unit was on production in just 105 days. We were able to cut the time to first production in half, and bring forward production nearly 15 weeks compared to a pad not utilizing simultaneous operations.

Advancements like SIMOPS will be important as we drill more large multi-well pads. Even so, as previously stated, pad operations lead to lumpy growth, and that, combined with winter operations and spring breakup will lead to back loader production again in 2014. Improving upon the efficiency gains of simultaneous operations will be important in helping us to deal with unevenly loaded pad operations.

It is also important to remember that we remain focused on well performance and well returns. We have performed a variety of completion styles in order to find the optimum frac design for each area. Along with other operators, we have tested a number of new frac techniques. We will continue to monitor results and modify designs when economics of the wells warrant the change.

Finally, given the success of OWS and our increased activity, we have ordered a second frac spread. It should begin operations late in the second quarter of 2014, and when combined with our existing frac spread, should handle approximately 50% to 60% of our wells. The decision to add a second crew was obviously pretty easy, given our success with our first crew.

As you can see, we have a lot of exciting things on the horizon. With that, I will hand the call over to Michael.

Thanks Taylor.

I'll begin with a brief update on the acquisitions. The closing of the West Williston acquisition was on October 1. Other than production guidance provided by Taylor, we are leaving all other financial guidance ranges the same for the full year. To fund the acquisitions, we raised $1 billion of senior notes and drew approximately $600 million on a revolver. With $145 million of pro forma cash after the acquisition, and $900 million of availability on the revolver, we have more than $1 billion of liquidity to fund our accelerated drilling program.

While we have ample capacity under our revolver to fund development, we also remain focused on maintaining a strong balance sheet. We discussed our intent to delever through growing production over the coming quarters when we announced our four transactions in September. And we also commented that we intended to aggressively hedge in the near term. We were able to lock in some attractive hedges over the past two months, adding contracts of about 6,500 barrels per day in 2013 and about 3,500 barrels per day in 2014. We have also looked for other options to help delever. In fact, you may have seen that we have recently put our non-operated position in Standish on the market. We just started this process, so we will see how it ultimately [phases] out.

The four acquisitions that recently closed added large operated blocks adjacent to our own, increased our inventory by 42%, and provided us an opportunity to add scale in an area we are familiar with. As we leverage the strength of our operating abilities, the assets are an important component to our resource conversion strategy. The acquisition added approximately 854 gross operated well locations to our inventory in some of the best areas of the Basin. And our drilling spacing unit, inventory has grown by 119 to 399 units.

With the acquired assets, we are determining the best options for developing the infrastructure. Our team has done a phenomenal job on our legacy assets and we can take the best practices to the new assets, where we can either put in infrastructure via in-house efforts or through third-party build outs. For natural gas, Oasis standalone has over 95% of its wells connected to pipeline. And the West Williston acquired assets are connected at a similar level. For oil, Oasis standalone had about 85% connected to pipe as of September 30, whereas the West Williston acquired assets were just over 25% connected. There's an opportunity over the coming quarters and years to get this number up and the team is actively working on options now. We're obviously trucking a little bit more now, which drives differentials a little wider than they otherwise would have been going into the fourth quarter.

We now have almost 60% of disposal water on pipeline and almost 90% going down our own disposal wells. The acquired assets are a little behind us, with about 40% on pipe and 60% going down owned disposal wells. We will be able to invest in saltwater disposal infrastructure on the position next year to help drive down LOE, which will be a little inflated from normal levels in the near term.

Looking at the third quarter results, our realized oil price averaged $100.75 per barrel, with about a 5% differential to WTI. As most of you know, differentials have been very tight since the fourth quarter of 2012, but they have recently started to pick up. We are expecting the fourth quarter to widen out a bit as compared to the third quarter, with WTI in Clearbrook to coastal markets spread gapping out again. We have shifted from as low as 40% rail in the third quarter to more than 90% on rail for November. This enables us to take advantage of the premiums that coastal markets are getting relative to WTI.

From a cost side, LOE ticked up a bit in the quarter to $7.18 per BOE. This is primarily the result of costs associated with more frac-protect activity while drilling offset wells. As we drill new wells close to producing ones, we'll continue to experience some frac-protect cost.

Adjusted EBITDA grew to a record $220 million as we realized $72 of EBITDA per BOE sold.

To close out we have a lot of good things in store for us and we are confident in the direction we are heading. With that we will turn the call over to Tony to open the lines up for questions.

(Operator Instructions)

Philip Johnston, Cap One.

I just wanted to get some clarity on your third quarter CapEx figures that you provided in the table. Two questions; first, on the $127 million of acquisitions related to your -- CapEx related to acquisitions, is that just cash paid for the East Nesson properties and the deposit on the West Williston transaction? Or does that also include some actual CapEx that you have incurred on the East Nesson properties after you closed it in September?

That is exactly right, Philip. What you said first, which -- that is the East side acquisitions, so payment for that as well as the deposit for the West Williston side, obviously that closed October 1, so you will see the full amount of that CapEx in the fourth quarter numbers.

So the clean EMD CapEx is more like $244 million or so? I was trying to square that number to the $8 million per well completed cost that you achieved in the quarter. If I take the $244 million and divide it by the 29.6 net wells that you brought online, it implies that little over $8.2 million per well. Just wondering what the delta is. It is probably just a timing difference in terms of CapEx allocation from quarter to quarter but I wanted to clarify that.

There's some of that and there is some infrastructure cost in that number as well. So as you back out that for the salt water disposal infrastructure that we put in, as you back that out that is how it rectifies.

You mentioned additional lower Three Forks benches next year. And I may have missed this but, did you say what the percentage mix will be between the various benches within the Three Forks? Just as a follow up, will most of those lower bench tests be single well tests, like the four that you have drilled? Or is the plan to move more towards multi-well, multi-formation density pilots like some of your peers in the field are doing?

We didn't talk about the percentage of wells that will be lower benches. But we did say that in the next two quarters you'll have 15 wells drilled in the lower benches. Overall, Three Forks and Bakken well count will be roughly 50/50, pretty well-balanced. In the areas where we have greater confidence in the lower benches, we will be drilling out some spacing units. Where we will drill across all the horizons, so Middle Bakken, first bench, second bench and potentially third bench. Then, in areas where we don't have quite as high a confidence, it will be more one-off type of wells testing the lower benches in those areas. Right now, the greatest confidence is more in our Indian Hills and South Cottonwood areas, and we are testing some of the other areas in lower benches.

Okay. That makes sense. Thanks.

You bet.

Dave Kistler, Simmons and Company.

Morning, Dave.

If I look at the 210 gross wells you are drilling next year, and the cost estimates you guys have put out, adjust for working interest, it gets you to somewhere between $1.1 billion to $1.2 billion for CapEx before infrastructure, et cetera. Is that a good way to start thinking about 2014 program?

Yes. That is not bad. I think you're -- it is pretty straightforward. I think you're in the range.

Okay, appreciate that. As we think about the guidance for Q4, what is the current or exit rate of the acquisition in terms of a production basis? I think at the time you announced the acquisition was about $9,300, has that declined since then? Where do we sit on that as we think about production going forward?

Dave, right now it is pretty similar to what we announced at the time of the acquisitions, so it is in that same range. However, as we progress through the fourth quarter, on those assets we are drilling on pads, and so won't have as many completions as we might otherwise have. So you may see that drop off a little bit, but we have got the ability to make that up on our remaining assets.

It will be kind of flattish.

Okay. I appreciate that. That is helpful for understanding what your base growth is from the original asset base. One more, as we think about completing less wells in Q3, is that just the nature of some slipping into Q4? And what does that mean with respect to possibility that Q4 comes on stronger than anticipated, or really more so with the acceleration in rig count, 2014 coming on stronger than anticipated?

I think a lot of it is just timing of wells, when wells come on relative to a day that is the end of the quarter. We were still pretty close. We are still targeting the 128 for the year so we will catch up. I think there is five incremental, [brett], that are on the acquired assets, so the original 128 plus 5 will put you in the range for the fourth quarter.

Okay. So the slippage of those didn't have anything to do with the CapEx reduction, it's purely drilling efficiencies that are driving the CapEx reduction?

Yes.

Okay, that is very helpful. Thanks guys.

You bet.

Noel Parks, Ladenburg Thalmann.

A couple things, -- overall given that you enjoy such a nicely concentrated acreage position, what is probably the biggest advantage that you guys can exploit there compared to your competitors who are more far slung? Is it getting the full development faster, gas takeaway being simpler?

What I would tell you is, a couple things, one is understanding and consistency relatively of the subsurface. While these wells are getting pretty close together, we still see -- we still tend to have a few surprises. But then the other one, I think that is probably the biggest thing is just infrastructure. Whether it is gas, oil, water, water gathering, water distribution. The whole bit, but I think it is largely infrastructure.

Infrastructure is big. Having concentrated positions is also going to help out as you go to drilling at density on the spacing units. Were you have got to take into account offset wells with frac protect and having a concentration of your own wells you don't have to deal as much with you impacting third parties and them impacting you as well. You can control that, so that helps out.

Right, great. I don't know if you touched on this already, I hopped on a little late. But as we look ahead to the year-end reserve bookings, I'm trying to think through, you have got a lot of drilling so I am thinking number of locations on the plus side should grow considerably. The two things I was wondering about, as far as the five year time booking limit, a sense of how much -- I don't know how you quantify it, how many of the locations are going to wind up in probables that in a more unlimited capital situation would be in the proved or in the PUD area? And then also, when do you expect you are going to see significant performance improvement bookings?

When you look at our overall reserves were not in a position to comment on what it is going to be at year end. We are at a little over 215 million barrels currently. Our PUDs relative to overall proved is at 47%. And when you look at the number of wells that we have booked as PUDs relative to the number of wells we drill in a year, you would burn through that full amount if you drilled all those PUDs in a couple of years. Staying within that five year window is really not going to be a problem for us.

Okay. The performance improvement?

Like I have talked about in the past, we are consistently focusing on improving the results on our wells. So doing that through stimulation, looking at optimizing fracs both what we are doing and what other operators are doing in the basin. So we have got to focus on trying to improve that all the time. But I can't tell you or give you a projection about where that is going to go.

Keep in mind that our reserves are prepared externally, not audited externally. And they are going to largely work off of the historical performance, so it is not like we are rolling into PUD some expectation of performance improvement. It is largely working off of the historicals, isn't that accurate, Brett?

Thanks a lot.

You bet.

Michael Hall, Heikkinen Energy.

First, noteworthy shift in posture around density tests and bench tests and your game plan on that, how quickly do you plan on testing, like you talked about the 15 to 20 well unit, how quickly are those sorts of tests going to make their way through the system?

Those we have got a couple of units that will drill at pretty high density but they are second half of the year, next year. We will be able to drill them -- it will be about six months or less to work through because we are going to apply multiple rigs to get them drilled in a reasonable amount of time so that we don't have too long of a lag between the first spud in those units and then getting to first production. You won't see impact from those until 2015.

Keep in mind Michael, as Taylor talked about, we have got about 15 lower bench tests over the next couple of quarters. So that will be helpful in how we lay those things out going into the second half of next year.

Okay that's helpful. Somewhat related then on the 210 gross drill wells, any rough numbers or percentage on how many get completed in the year? And how those are spread out, broadly, through all your different areas.

When you look at the total count, you probably -- because of the pad drilling and especially those big units I was talking about that are going to be over the end of the year. If things work out like it looks like, you are probably going to be more in the 180 range in terms of completed wells versus the 210. We're still working through all of that. And that is the kind of data we'll be able to give you when we talk about our budget in February. As far as a mix throughout the year, again it is going to -- you're going to have back-loading effects because of winter operations and putting as many of our wells on pads as we can during the break-up period so more wells completed in the second half.

Any relative emphasis in any of the sub areas within your acres position? Or is it going to be pretty well spread out throughout the whole acreage position?

We're trying to receive a pretty good spread with the 16 rigs. But again, we can give some more color on that when we come out with the budget in early next year.

Fair enough. Do you have comparable, last one for me, comparable IP 30s on the offsetting Three Forks wells relative to those deep tests you highlighted?

You mean from other operators?

Yes or yourselves to prior wells drilled nearby. Trying to understand how those --

For example, the Polletts well, you had a 30 day IP of 712 barrels a day. There are two areas -- two first bench wells around it. And the Pollett was a second bench. You have two first bench wells that were around 775 barrels a day for a 30 day average and you had one well that was about 1,100 barrels per day for a 30 day average.

Okay, that's helpful. Appreciate it. Thanks guys.

Bye, Michael. Thanks.

Tim Rezvan, Sterne Agee.

I had a quick one on the Sanish assets being marketed. Should we assume it's all -- 8,000 net acres and about 2,800 barrels of production?

That is what we have on the market.

I appreciate that clarity. Should we think about that, that will help fund the infrastructure ramp that you signaled on the recently acquired acreage?

That is something that we are looking at that will help with the balance sheet overall, Tim. Obviously that is a great premier asset, and we expect it to be highly contested for. That will help us with our liquidity and helping us deliver the balance sheet too.

Just asking in context because you can see the debt to EBITDA decline pretty sharply out to 2014. Should we look at recent ratios in that 1.5 times range as management's comfort level?

We have said that we would like debt to EBITDA to come down to under two times and that would be a level that we are comfortable with. Like you said, we know that as production grows we can see that coming down over the next coming quarters. This is just one of those things as we are accelerating, we feel good about the inventory, continuing to accelerate a little bit. Like you said, there'll be some infrastructure build. So managing CapEx and the cash flow outspend and managing that balance sheet.

Okay, thank you for the color.

You bet.

David Snow, Energy Equities Inc.

Could you give us a little color on the completions that you're experimenting with. The different ones that you and others are doing as submitted liners, a big part of that is more profits per foot or different frac fluids? If you could help with them and what kind of responses might you have gotten so far?

We have actually experimented with all of those things you talked about. Some of the recent things you have heard the industry talking more about have been; slick water fracs and then fracs of higher profit concentration, higher, bigger fracs overall. We have experimented with those, as well as looking at all of the other operator data in the basin. And that is where we come back to making -- we'll make adjustments to our typical fracs by area based on what we see with all that work. We're not in a position to talk about what results are for each of those individual fracs other than tell you that we are optimizing relative to what we see in each of the areas in which we produce.

Are you liable to see some increase in your IPs and EURs as a result of all of this?

You know, when we look at the data, some of those frac styles in some of the areas do increase IPs, but they can also have other effects like higher water cuts and then, along with it, you have got higher cost. You have got to balance the higher cost versus, not only IP but what is going to be EUR in the wells. Is it just acceleration or are you really increasing reserves and then what is the economic impact. For us, we have got tight curve ranges that we have been using and those are -- we haven't changed those at this point and if we get to a point where we really see a significant uptick we will let you know.

And is liners a big part of this or have you been doing that all along?

We primarily use swell packers but we have done cemented liners, probably 10 to 15 wells overall. Looking at the results but right now our standard completion is still the swell packers.

Thank you.

You bet.

Ron Mills, Johnson Rice.

As it relates to the down-spacing, you have 13 of the 22 online and you talk about encouraging results. Were you expecting much if any degradation as you were going through this? Are you positively surprised or not? Corollary to it is given the fact that 38 completions during the third quarter you were still able to come in a little bit above the midpoint of your range. Am I reading too much into that in terms of the way the well performance is holding up relative to your curves. It looks to be a little bit better than that.

What I would say Ron, I think we would expect the wells, at least early days, to perform consistent with the offsets. You are just too early time. The good news is, is that you are not seeing degradation. So they are performing in line with what we expected. That is probably about, given the time frame that we have got, probably about all you can say about it at this point.

I really wouldn't expect a lot of degradation early time. If you talk about in the past, it is watching production combined with modeling and pressure monitoring and pressure work to really understand what the drainage is going to look like.

Taylor, you mentioned the 2014 growth profile will also be back-end weighted, similar to 2013. Is that something we need to think about from an overall seasonality standpoint? Where you have a little bit of growth in the first quarter from the fourth and flattish in the second and then most of the growth in the second half, is that something that is steady state as we go forward or does that become less seasonal in 2015 and beyond once more infrastructure is in place and you are less dependent on weather related downtime?

It is probably a pretty good, decent assumption that it is going to be, in a typical year, back-loaded. And it is all around, some of it is winter and that a lot of it is around to break up when you just can't move equipment. Roads close and you have the road bans on. Even if you got the infrastructure in place, you can't move sand and other equipment to frac with. So you tend to plant your rigs and the effect of that is it pushes out those completions into third and fourth quarter. There's been exceptions to that. If you look at historical reduction in years where it is cold and wet, you really see that flattening in the first two quarters. In years where it has been unseasonably warm and not a lot of rain, we have had a pretty even ramp and a good example of that is in 2012. In 2011 and 2013 you see that more typical pattern of flat in 1Q and 2Q and then back-loaded increases.

We will continue to plan that way, Ron. It just doesn't make a whole a lot of sense to us to spend a lot of money to fight the weather. We have shown that we can pretty effectively manage that this year. That is the way we view it.

Just on the Three Forks, the wells that you drilled this year, not just to the upper, but also the second and third. Have those been spread fairly well across your different operating areas? Have they been concentrated in particular areas, and I assume given next year is going to be more balanced, I am assuming it is good to be spread across more of your operating areas, is that also the same for the lower bench or is the lower bench more concentrated in terms of testing?

For second bench wells -- a lot of activity by other operators, more central deeper part of the basin, and we have got tests in those areas. But we also now are stepping out and like we talked about, drilling this well -- it's waiting on completion at North Cottonwood. Third bench test, at this point they are in Indian Hills and the well that we've got drilling in South Cottonwood, the Mangum well and just one of those being online at this point. But we will have some units were we will likely drill third bench. As Tommy talked earlier about the 15 wells that we are going to drill on the lower benches in the next two quarters as we get those results. That would then result in more lower bench tests in the back half of the year.

Are those 15 to 20 going to be more concentrated in places like Indian Hills or will you also scoot over to South Cottonwood?

They will be Indian Hills, South Cottonwood and North Cottonwood at this point. We are also looking at some of the acreage to the west that we picked up, which would be Painted Woods and then also in our eastern Red Bank area we have a second bench test that we will be drilling.

Perfect. Thank you guys.

Thanks, Ron.

Irene Haas, Wunderlich Securities.

I just wanted to get a feeling for your Three Forks Sanish benches. How extensive is it? Is controlled by drill depth or is it precedent to us in North Cottonwood area?

If you remember, Irene, last year we -- and the beginning of this year we took a lot of cores and really evaluated the subsurface and that is where we're getting to the interest in where we're drilling wells. We see second bench potential across the areas we just talked about. So parts of Red Bank will be testing, potentially Painted Woods, Indian Hills, South Cottonwood and North Cottonwood. Then, third bench wells, early time, but at this point we've got tests in the near term planned for Indian Hills and South Cottonwood.

Great. Thanks.

Thanks.

Peter Mahan, Daugherty.

I just had a couple of follow up questions. What can we expect in terms of working interest over the next couple of quarters? And I think we increased from roughly 70% in Q2 to 73% here in Q3. How should we think about that trend for the foreseeable future?

Our working interest position ends up being around 70% on our operated acreage, Peter. We normally come in at somewhere between 70% and 75% on working interest, so it will all fluctuate in that ballpark.

I know we talked about the Sanish acreage that you are trying to sell, that has been put on the market. In terms of the inventory you guys talk about, what is the number associated with that acreage?

Remember that Sanish position is all non-operated. So as we start -- we talk a lot about our gross operated inventory. When we talk about basically 400 drilling spacing units in our operated inventory that net drives -- as you go by our old inventory slides it has four by four and now those potentially could be a little bit higher than that. That is really our drilling inventory that we really talk about. And Sanish is, remember, all non-op so it's not included in that.

Okay got it. So you guys have not quantified that to any degree?

It is in the back up on page 23 of our presentation, that is all broken out.

Finally, I apologize if I missed it. Could you walk through your infrastructure expense, CapEx expectation for 2014? I know we talked about $20 million for the second frac crew, but could you walk through some of the other parts to that?

Infrastructure costs will be a bit variable. We will have to figure things out a little bit. Obviously we have been running more in a $50 million neighborhood per year. Most of that was salt water disposal-type infrastructures around our Legacy assets. This year, as we talked about in the infrastructure side with the new acquisitions, there is an opportunity for us to potentially do some of this in house on, not only salt water disposal, but even on oil and gas. We are going through that process of figuring out are we going to go with third party on that, or are we going to do some of that internally. That capital actually can fluctuate a little bit depending on which direction we head on that.

John Wolff, ISI Group.

Maybe one for Taylor. Trying to think conceptually about the ability to go beyond four plus four. If you are drilling more wells per section, does that speak to recovery rates per well? I know Taylor and I discussed the idea of 3% to 5% recovery per well, within a drilling spacing unit. Is more wells just more infill drilling of the same resource or is there a tendency to think that you'll get equal results or similar on more well count?

It depends on, kind of depends on the area. But the well counts we are talking about going from four to five we think the EURs are going to be pretty simpler. You may see a little degradation, a little bit of competition for reserves but it is going to be more weighted to the tail so it is out in time. The 3% of 5% is still a good number to think about. We talk a lot about as we are figuring out spacing, triangulating with a lot of different data sources. And one of those is oil in place and overall recovery in an area. So for a spacing unit, we think that somewhere in the 15% to 20% total recovery is reasonable. And then as you are taking those wells that are each recovering 3% to 5%, you can start doing the math on what that might look like. Going from four -- depending on the area thickness and reservoir quality and all of those things going from four to five to potentially six wells, you're potentially going to see some degradation but at this point we don't think it is mass, we have to do more work on it.

Am I right to think that the four plus four or five plus five would be a combination of middle Bakken and then either/or Three Forks one or Three Forks two?

I will just give you an example. You have got to evaluate each of the intervals and then how the stimulation interacts and also how they produce at post-stimulation. But those larger units, those units where we're going to produce or drill more wells up to 15 to 20 next year, we are contemplating drilling roughly 5 in each of the intervals. So you can have five Bakken wells, five first bench, possibly four second bench and then also third bench wells also. You would have them spaced throughout each of the producing intervals if those intervals are productive in that area.

I would now like to turn the call back over to Mr. Lou for any closing remarks.

This is Tommy. Oasis continues to differentiate itself as one of the premier operators in the Williston Basin. Our team performed exceptionally across the board in the third quarter. We executed again operationally, hitting our volume targets and managing costs. At the same time we added to our asset position significantly with four acquisitions. We now have them closed and have been doing an exceptional job on integration. This has been a tremendous year for us so far as we have done the things to grow our inventory, managed costs and improved economics of our business and increase the resiliency of our inventory to low oil prices. All of these things of strengthen our plan and make us very excited about what the future holds. As always, thanks for everyone's participation on our call today.

Again, thank you for your participation. This does conclude today's conference call. You may now disconnect.