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Oasis Petroleum (NYSE:OAS)

2013 Operating Results Call

February 04, 2014 11:00 am ET

Executives

Michael H. Lou - Chief Financial Officer and Executive Vice President

Thomas B. Nusz - Chairman and Chief Executive Officer

Taylor L. Reid - President, Chief Operating Officer and Director

Analysts

Irene O. Haas - Wunderlich Securities Inc., Research Division

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Stephen F. Berman - Canaccord Genuity, Research Division

Andrew Venker - Morgan Stanley, Research Division

Michael Hall

Daniel Braziller - Jefferies LLC, Research Division

Timothy Rezvan - Sterne Agee & Leach Inc., Research Division

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

Dan McSpirit - BMO Capital Markets U.S.

Philip Johnston

Joseph B. Stewart - Goldman Sachs Group Inc., Research Division

Operator

Good morning. My name is Justin, and I will be your conference operator today. At this time, I'd like to welcome everyone to the fourth quarter operating and preliminary financial results 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.

Michael H. Lou

Thank you, Justin. Good morning, everyone. This is Michael Lou. Today, we are announcing 2013 operational and preliminary financial results, as well as discussing our operational plans for 2014. We have prepared this summary of preliminary financial data based on the most current information available to us. However, our audit and normal financial reporting process had not been fully completed. As a result, our actual financial results could be different from the summary preliminary financial data, and any differences could be material. We intend to release complete 2013 financial results on February 25, 2014. This call will take the place of the call that we have historically done around our earnings release. 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 risk and uncertainties that could cause actual results to be materially different from those currently disclosed in our press release and conference call. Those risks include, among others, matters that we have described in our press 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 call, we may also reference -- may make references to adjusted EBITDA, which is a non-GAAP financial measure. Reconciliations to adjusted EBITDA to the applicable GAAP measures can be found on our website. I will now turn the call over to Tommy.

Thomas B. Nusz

Good morning, and thanks for joining us today. This call is a bit of a departure from the past where we had the call when all of our fourth quarter numbers were completely finalized. In light of the significant growth we've experienced over the last year, we felt that it would be more useful to you to have the call early to cover the highlights and results from 2013, latter plans for 2014, then provide an opportunity for questions. As you may have heard us say over the last couple of months, 2013 was both a transitional year and a transformational year for Oasis. And I'm very proud of what the team accomplished in 2013. With all of our acreage effectively held by the end of 2012, we entered 2013 focused on the transition to pad development, incorporating test around defective down-spacing and resource potential in the lower benches of the Three Forks. But not just evaluating the number of wells for drilling spacing unit or DSU, but also the logistics of developing full DSUs and improving well economics. Our work is not done but the team executed well on all fronts, setting us up for our first full DSU development projects in 2014. At the same time, we completed 4 accretive acquisitions. All of this activity has resulted in significant growth on multiple metrics including volumes, reserves, acreage and inventory, while continuing to optimize well cost. So in 2013, we had 4 key accomplishments that I would like to draw your attention to. First, we were able to complete 136 gross operated wells, which was 8 more than we had budgeted, and we estimate we will spend approximately $40 million less in drilling and completion capital. We're continuing to get more efficient as we've driven our well cost down from $8.5 million in the fourth quarter of 2012 to $7.5 million as we exited this last year, including the impact of OWS. Second, we were able to grow our annual production by 51% in 2013 to 33,900 BOEs per day with fourth quarter production of 42,100 BOEs per day. Our estimated net total proved reserve grew by 59% to 227.9 million barrels, while the PV-10 of our estimated net proved reserves has grown by 69%, up to $5.5 billion. Third, we were able to increase our net acreage by 54% to 515,000 net acres. This was largely as a result of the significant acquisitions where the team has done a tremendous job on integrating the assets into our operations, but also where our team was able to high-grade acreage, adding additional interest in our existing operative blocks, as well as new blocks. Fourth, we expanded our inventory with tighter down-spacing and additional lower bench Three Forks wells. We now have 3,590 gross operated drilling locations, up 78% year-over-year, which provides us approximately 17 years of drilling inventory with our current rig plan. The inventory will continue to evolve over time as we find ways to maximize the economics of our 403 operated DSUs. With that, I'll hand the call over to Taylor to provide more color around our operations.

Taylor L. Reid

Thanks, Tommy. In 2013, we focused on the transition to full DSU in field development through evaluation of the Three Forks, infill spacing and optimization of surface operations. The first component we focused on was a lower bench of the Three Forks. We cored 7 wells through the Three Forks and conducted extensive core and log analysis, and based on those results, developed our Three Forks drilling program. We currently have 5 lower bench Three Forks wells on production. In Indian Hills, 2 second bench wells, the Paul S and the Patsy, as well as a third bench well, the Omlid, are performing in line with Three Forks wells in the area. On the east side, we have also been encouraged by the results of our first 2 lower bench completions. In South Cottonwood, the Mangum, our first third bench well in the area, has been on for 25 days and averaged 944 barrels of oil per day in its first 7 days and 580 barrels of oil per day since it went on production, in spite of flowing at restricted rates since that first week. In North Cottonwood, the Bonita, our first second bench well in the area, has been on pump for 25 days. During that time, it averaged about 150 barrels of oil per day at a 73% water cut. And in the last 5 days, averaged 180 barrels of oil per day at a 70% water cut. This profile of increasing oil and decreasing water production is typical of both Bakken and Three Forks wells in the North Cottonwood area, and as a result, leads us to be optimistic about the second bench in the area. Keep in mind that well cost in North Cottonwood are generally our lowest at around $6.8 million per well. Given these successful lower bench results on the east and the west sides, we plan to complete approximately 30 lower bench Three Forks wells in 2014.

The second key aspect to understanding the subsurface is related to the infill density testing. We have 16 of our 22 density tests currently producing. Results from these tests have been positive, and when combined with our work on oil in place, reservoir modeling and pressure testing, lead us to believe that on average across our position, we will drill approximately 10 wells per DSU. The areas will be spaced differently depending on the reservoir in that area. Across our 403 spacing units, we have grouped the inventory into 3 buckets. The first are spacing units where we expect to drill 15 or more wells per unit. The second are DSUs where we expect to drill 10 wells, and the third, where we expect to drill 7 wells. The DSUs and the 3 buckets account for 26%, 40% and 34% of our total 403 DSU count, respectively. Keep in mind that these counts include second bench wells only in Indian Hills and South Cottonwood, and no third bench wells in any area.

As Tommy mentioned, we now count 3,590 wells in our drilling inventory, and with a little over half of that in the Three Forks, we wanted to revisit our average type curves for our formations. For the Bakken, we continue to use the range of 450 to 750 MBOEs with the midpoint of 600 MBOE. For the Three Forks, we have seen on average about a 15% reduction in performance as compared to Bakken wells in the same area. As a result, we have moved our Three Forks range to 400 to 600, with a 500 MBOE midpoint. We are excited about the significant expansion of our inventory and look forward to updating you as we collect more data in the lower bench test and in our inner well spacing test. We also made significant progress in our infrastructure in 2013. Including our acquisitions, approximately 75% of our oil is collected in a gathering system and trunk line operated by Hiland Partners. Our newly acquired assets are not quite as mature with respect to infrastructure as our legacy assets, so we see a lot of opportunity to build out the infrastructure and improve margins. On the GAAP side, we are in good shape with 93% of our wells connected to a gathering and processing system. We will continue to work to get the connected well count percentage up, as well as to minimize flare of [ph] gas. On the waterfront, we have more than 75% of our produced water going into our own disposal wells and a little over 50% transported through our gathering systems. As you know, this system is owned and operated by Oasis through OMS.

Moving more of the produced water through our facilities will provide an excellent opportunity to improve our lease operating expense in 2014 and beyond. In addition, in certain areas, OMS will be supplying our wells with fresh water for both operations and frac jobs. Piping the water to well sites saved us approximately $1.50 per barrel or about $100,000 on a typical 65,000 barrel frac job. As it makes sense, we'll continue to implement this throughout our position. I'd now like to shift our attention to 2014, which will focus on 4 key themes: inventory acceleration, subsurface well density, surface pad operations and cost control, and well performance. First, as we have significantly grown our inventory, we have made the decision to accelerate its development. We are currently running 14 rigs and plan to add 2 rigs in the middle of the year. With the additional rigs, we are expecting to average between 46,000 and 50,000 barrels of oil equivalent per day. Keep in mind that we have seen a pretty cold winter, thus far, with impacts to production since late November that have carried into this year. That, combined with the focus on pad drilling through the winter and breakup, results in a production profile that is backloaded as in previous years, with about 60% of our completions occurring in the second half of the year. Also remember that we have eliminated production from Sanish assets from March forward at a producing rate of about 2,700 barrels of oil equivalent per day. As a result, we are estimating that the first quarter will fall between 41,000 and 45,000 barrels of oil equivalent per day. We will achieve this growth with a total capital expenditure budget of $1.425 billion in 2014. With about 90% of it going to the drill bit, we expect to complete 205 gross operated wells and 155 total net wells, including non-operated wells, for a 35% increase over 2013. The remainder will be spent on other items such as lease hold, infrastructure, geology and equipment for our second OWS frac spread. The second and third themes go hand-in-hand as the subsurface well configuration dictates the number of wells captured on our pads. With respect to the subsurface, you will see us drill more and more full DSUs as the year goes on and especially as we move into 2015. This translates into higher density pad drilling. In our 2014 program, we expect to spud nearly 90% of our wells from multi-well pads compared to 60% to 70% of our wells in 2013. With larger pad sizes, we can generate further efficiencies and cost reductions that should drive our well cost to $7.3 million, including the impact of OWS by the end of 2014. Finally, we'll be focused on improving our well economics through both cost reductions and completion techniques. On the west side of our acreage, early production results from slick water fracs have performed in the top quartile of wells in certain areas. Remember that there is an offset to this well performance and well cost as slick water completions cost $1.5 million to $2 million more than our typical wells. Given the results, we will perform 15 to 20 more slick water fracs in 2014. There is still a lot of work to understand the EUR impacts associated with the fracs, but we are cautiously optimistic that it will result in an increase to well economics. In addition to slick water, we continue to test a number of other variants with respect to our stimulation techniques. In summary, we have come a long way this year in setting us up for full field development. With that, I'll hand the call over to Michael?

Michael H. Lou

Thanks, Taylor. We had another great year, and I will give a quick review of some of the preliminary financial and operational numbers. Production was just inside our guidance range as we produced 42,106 barrels of oil equivalent per day for the fourth quarter. In spite of harsh winter conditions, which impacted the second half of the quarter, the team was able to deliver inside the range. While we experienced record low differentials through the first 3 quarters of 2013, differentials widened out in the fourth quarter to an estimated 12%. Recently, however, Clearbook differentials have tightened up to WTI, so we are expecting our differentials to come in a bit in the first quarter of 2014. Ultimately, we still believe the long-term differential will average around 8% to 10% discount to WTI, although it may fluctuate above or below that level. Due to the acquisitions and a pretty severe winter, lease operating expenses increased in the fourth quarter. The acquired assets carry a higher operating cost, and we are expecting 2014 LOE per BOE to be higher than we've experienced in 2013. But we'll be able to work that down over time as we integrate the assets with our best practices and added infrastructure. We have taken over operations of the acquired assets at the end of the year, and it will take us approximately 6 months to integrate it into our processes. We are expecting to close the divestiture of our non-operated assets in and around our Sanish position later this quarter for approximately $333 million, subject to customary post close adjustments. The divestiture helps de-lever our balance sheet and will provide additional liquidity for our operated drilling program. As you think about production forecasting for 2014, production from Sanish will be included for the first 2 months of the first quarter and then eliminated after that. To close out, the team performed well and we had tremendous results in 2013. The next stage of the Oasis story full field development will continue to drive operating results. With that, we'll turn the call over to Justin to open the lines up for questions.

Question-and-Answer Session

Operator

[Operator Instructions] And your first question comes from the line of Irene Haas with Wunderlich.

Irene O. Haas - Wunderlich Securities Inc., Research Division

So aside from your divestiture of your non-ops stuff, are there any other sort of assets within your portfolio that could be useful for further debt reduction?

Michael H. Lou

Not at this time, Irene.

Operator

And your next question comes from the line of David Tameron with Wells Fargo Securities.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Just strategically, Tommy, how should we think about -- I guess, 2 questions. One, did you give us a price that you set your capital budget on for '14? And how should we think about how you're looking at the crude curve going forward and some of the backwardation and -- are there prices [indiscernible] level where you start to pullback or can you just give us some thoughts around that?

Thomas B. Nusz

Yes. So this year, the base budget is $85 to $90, is the way we've looked at it. Actually, it's a bit up from what we've done in the past where it was $80 to $85. But I mean you kind of look at the curve for actuals for the last 3 years and it -- based on that, we felt like it made sense to bump it up just a bit to be true to ourselves. But -- and as we look forward, you'll notice, for instance, we don't have anything. We've got about 21,000, I think, hedged for 2014, but we don't have anything hedged beyond that. We're kind of watching the curve here. Seems like the thing is, it's staying backwardated but it's just moving forward. In fact, I think it's up a bit today, but 2015 is -- has been a bit kind of anchored, but -- then more recently moved down a little bit. So we're just kind of watching it to see where that goes. From an activity standpoint, we're going to accelerate this year, driven by the increase on our inventory going up to 16 rigs through the year. And we'll keep an eye on what the curve is doing. But as a practical matter, as we've said for some time, as we start to see visibility down around $70 to $75, call it $70, with normal differentials, we'll start to power down, and all of our structure and contracts are set up to allow us to do that. But keep in mind that, too, is based on current well cost. So -- and then as we go down, if we do, to call it $50 to $60, we still got a good bit of inventory -- a lot of inventory, actually, that's economic, very economic down in that price range. So that we can continue to drill with, call it, 6 or 7 rigs, in that low price environment, kind of tread water on volumes and live within cash flow. So that's basically how we look at it.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Okay, that's helpful. Good color. If I think about -- how should I think about the DSUs? I mean you're now talking 10 DSUs. I know in the past, you said that you think that number goes higher. Can you just give us some color what you think the -- a realistic number is? I'm talking wells per DSU.

Taylor L. Reid

Yes, so we've -- we're seeing on average that it is 10 wells per DSU across the position. But as we highlighted, those areas where -- it's primarily to the west where the reservoir is thinner. Right now, we're seeing it's 7 wells. And then we've got, in the central part of the basin where the reservoir is thicker and you have higher oil saturations, we think it's 15 or more wells per DSU. And then in the east side in the North, we think it's 10 wells there. And so it depends on where you are in our position, and that's based on all the work that we've done with respect to the down-spacing test, oil in place, amount of drainage that we expect, and then modeling. It's when you put all those things together, that's just the current view. As also mentioned, we think there continues to be upside to this number, both in terms of potential tighter spacing in each of the formations and also in the lower benches. We've only included the second bench in Indian Hills and South Cottonwood, and we don't have any third bench included in the inventory, currently. So it's based on what we feel comfortable with right now.

Michael H. Lou

Keep in mind, Dave, as in a lot of cases for some of this stuff, what we've said consistently is that we like to approach it from one direction, and the inventory is no different. So as we gather more data, we like to step in an orderly manner upwards and kind of give you, at least as, for lack of a better term, number. And so this is the first step that we made in some time. And as Taylor mentioned, there may be a little bit more movement on density, and we've only included second bench Three Forks wells and South Cottonwood and Indian Hills. And so there's no second bench inventory anywhere else and no below second bench inventory in any of the asset position. So we're moving cautiously in one direction, and then we'll see where it plays out and add as we feel it's appropriate.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Okay. And then third and final question. Can you just talk about, Tommy, the rail? I know you guys have the flexibility to go rail or pipe. Can you talk about your thought on locking in longer-term contracts? And then if you want to comment on anything as far as the rail and regulation, if there's going to be any impact to you or other players, and I'll let somebody else jump on.

Thomas B. Nusz

Yes, I'll let Michael add to it, but I think -- I mean, you are going to see some impact of additional regulation with respect to rail, both in terms of the design of the cars and operating practices. Obviously, operating practices are things that you can change a bit more quickly than the real car fleet. But we haven't locked in anything on that front yet. And I think it's -- as this thing has evolved so quickly over the last 18 months, I think -- I mean, there really hasn't been a whole lot of option to do a lot of the long-term -- longer-term stuff that we -- what we consider to be reasonable prices. But we'll keep watching that. Michael may have a bit more to add on that.

Michael H. Lou

And it's a bit of a strategic move as well, Dave. And if you look at the takeaway capacity at, call it, around 1.5 million barrels out of the basin right now with production at about 1 million barrels out of the basin a day, there's a lot more takeaway capacity currently. And what -- why we have enjoyed slightly better differentials than some of our non-op positions is because we've been able to move back and forth between rail and pipe, and actually, get the best price on a daily basis. So we've got a great gathering system. We're almost -- we're largely gathered now on our oil properties, and we have the flexibility to move to the best price. As the takeaway capacity continues to outstrip production, we think that it's favorable for us to be in more kind of shorter-term type positions. As our position -- as our production continues to grow, we will start locking in to some long-term takeaway capacity. But until we see a longer-term move where takeaways constrain, we probably won't go to any high percentages of long-term agreements any time soon.

Operator

And your next question comes from the line of Steve Berman from Canaccord Genuity.

Stephen F. Berman - Canaccord Genuity, Research Division

Just a couple of questions. Can you tell us what the proved reserves associated with the Sanish divestiture?

Taylor L. Reid

As of year end, in our press release, we kind of break it out, West Williston, East Nesson, in Sanish. The Sanish piece is about 8.6 million barrels or BOE equivalents.

Stephen F. Berman - Canaccord Genuity, Research Division

Okay. And the remaining drilling locations, would you happen to have what the pud component of that this, either on a gross or a net basis?

Taylor L. Reid

Yes, just -- so total gross is 358 locations at our PUDs of the 3,590 of remaining inventory.

Thomas B. Nusz

That's on Page 20.

Taylor L. Reid

Page 20 of the appendix and the most recently posted -- we posted it this morning, the updated presentation.

Operator

And your next question comes from the line of Drew Venker with Morgan Stanley.

Andrew Venker - Morgan Stanley, Research Division

I was hoping you could discuss where your production is currently and if you think you've fully recovered from the winter weather or if there's still some production that has to come back online?

Taylor L. Reid

So as we talked about in -- starting really in late November, you had severe cold snap that went through most of December. A lot of 20 to 30-degree below 0 weather. So a lot of production got knocked offline with those storms, very difficult to get all those wells back producing again, also hampered our completion activity, number of frac jobs we can get completed. As we came in to January, it -- you had a pretty good warm-up in the first couple of weeks. So the ability to get a lot of that production back on, not all of it, but really, kind of get production back up and now, we're kind of back into the storm track that's hitting regularly but not as severely cold as in December. So you're going to see, if the weather continues like it has been, some impact, probably not as severe as we saw in December because, I think, we're past those just extreme cold conditions.

Andrew Venker - Morgan Stanley, Research Division

Okay. And then regards to the oil differentials, the -- those reports out that the Whiting refinery is switching over to running heavy. Do you expect that to have any meaningful impact on pricing for you guys?

Thomas B. Nusz

Yes, I think we did see a bit of that impact already, and then differentials have closed back. But as refineries move over to heavies, obviously, there is some impact to the light sweet in that area.

Andrew Venker - Morgan Stanley, Research Division

Okay. But it sounds like you're not thinking it's all that significant because your differential guidance is long-term, is where you had it before, I think, 8% to 10%?

Thomas B. Nusz

With all the rail capacity, as well as other options that are coming online, we don't think that, that will impact long-term differentials in the basin.

Andrew Venker - Morgan Stanley, Research Division

Lastly, just curious on service cost, if you're seeing improvements in day rates or completion cost, if there's any change to your year-end 2014 well cost target?

Michael H. Lou

We really haven't seen a lot of movement. Service costs, they've been pretty stable, and we expect them to remain that way in 2014. We'll see how it develops as the year goes on.

Operator

And your next question comes from the line of Michael Hall with Heikkinen Energy Advisors.

Michael Hall

I guess, I wanted to drill in a little bit on the EUR commentary and guidance, particularly on the Three Forks. I guess, I was just curious on that range. Can you kind of help us think about how that Three Forks EUR kind of varies across the footprint? And is there any sort of bias in the 2014 program in terms of where you're drilling Three Forks relative to the range provided?

Taylor L. Reid

So the -- that range across the position mimics what we've discussed in the Bakken previously. So the highest EURs you're going to see in the Three Forks are in the more central, deeper part of the basin. So South Cottonwood and Indian Hills will have the highest EURs and be at the upper end of that range. The lower EURs will be in the more distal parts of the basin, so North Cottonwood. And then, also, as you go to the west into Montana, you'll see those EURs drop to the lower end of that range. As far as concentration of wells, with just in general with the Three Forks, you're going to see a fairly even distribution across the whole position. We'll drill close to 60% of our total well count, will be Three Forks wells. With respect to the lower benches, and we talked about 30 wells there, most of those will be in that deeper, central part of the basin in Indian Hills and South Cottonwood, but also drilling some additional lower bench wells in North Cottonwood.

Michael Hall

Okay. That's helpful. So the 15% doesn't -- that reduction doesn't necessarily vary materially across area. It's just higher Middle Bakken tends to lead to higher Three Forks. There's no variability between how much reduction you see?

Thomas B. Nusz

Yes, I mean that 15% may vary a bit. But what you just said is right. But we felt like it was important to provide a little bit more granularity on the Three Forks given the magnitude that it plays and what the total program is. As Taylor mentioned, it'll be 60% of -- roughly 60% of the wells drilled for this year, and then a fair amount is lower benches. So we felt like from a modeling standpoint, it was important to kind of communicate that.

Michael Hall

No, certainly, it makes sense. And then, I guess, along those lines, I think the EUR, and just trying to think about you're doing a lot of down-spacing testing as well, have you seen any degradation in EUR? I know you've worked through the down-spacing and you've kept your Middle Bakken EUR aim constant. I'm just trying to understand what you're seeing there, and is there any kind of risk into that, that's implicit in the guide given how much down-spacing work you're doing in 2014?

Taylor L. Reid

So with respect to degradation in the EURs, and that's something we're working on, when you look at the spacing test, most of those being an early time, a year or less, you don't see any reduction in the well performance. They generally look like the wells that were existing around them. We continue to look at oil in place, predictive modeling and simulation and things like that, to get a better handle of as you go to higher densities, what you might expect in terms of degradation. But at this point, we're not -- we're just not in a position already to talk about that yet. We're still doing work on it.

Michael Hall

Fair enough. Makes sense. And then, I guess, last -- or I guess 2 on my -- one more is just both on cost. First, any -- can you give us the future development costs associated on that PV-10 provided, if I missed it? And then second was on the LOE and OpEx guidance. If we think about that, is it kind of linear from the fourth quarter of '13 to fourth quarter '14? If we kind of think about the front end being the highest or just trying to think about how to shape that throughout the year.

Michael H. Lou

Okay. So the total capital in that PV-10 number is about $1.8 billion, a little over that. And then with respect to the LOE, you're going to see it -- relative to what it was in the fourth quarter, because we closed on the acquisitions beginning of October, so you got full impact of the LOE. And the LOE on the acquired properties was -- is quite a bit higher than our existing LOE. So what you're likely to see, Michael, is Q1, it may move down a little bit, but because of the winter weather, probably not a lot, especially a winter like this. More likely in Q2 -- I mean, Q3 and Q4, as you get out of winter and break up, you're going to see it start to tick down more and get on a downward trend.

Operator

And your next question comes from the line of Dan Braziller from Jefferies.

Daniel Braziller - Jefferies LLC, Research Division

I was just wondering what 4Q CapEx was and if some of that spend got pushed into the '14, and if that was due to weather?

Michael H. Lou

I think, obviously, we did have some -- a little bit that got pushed. That being said, we still -- we completed well on production, 47 wells.

Thomas B. Nusz

And it's Tommy. We -- from a drilling standpoint, we got -- we didn't have a lot of problems with the rigs, a little bit on moves. It was mostly around the completion side of the business, so a little bit got pushed, but not gigantic...

Taylor L. Reid

Yes, so the $240 million or thereabouts that will be spent was spent in the fourth quarter. Most of that cost savings though was because of being more efficient. And so through the year, we spent around $50 million -- $60 million less than budget. Close to that was through cost savings, even though we drilled and completed more wells than we had on our budget. Very little of that capital will actually come into this year, a nominal amount from above what we otherwise would have budgeted. So we did get some work done in -- or through that. Even through that winter period, there are some wells that kind of come forward. But overall, it's pretty much a wash.

Operator

And your next question comes from the line of Tim Rezvan from Sterne Agee.

Timothy Rezvan - Sterne Agee & Leach Inc., Research Division

Looking at your net acreage position, about 515, it looks like from the deals announced in September, you've bolted on another 15,000, 20,000. It looks like it was across West Williston and East Nesson. Was there one big deal or can you kind of give a little color on that increase?

Taylor L. Reid

Yes, it -- we spent on land, about $25 million. And so with those land expenditures, we were able to increase our acreage position. And in addition to that, we had some top leases take effect and some other consolidation of positions be trades. And so when you put all that together, it's just kind of all over the acreage position, what we try to do every year to provide that normal acreage increase. When we talked about our numbers back in September, we didn't incorporate those increases at that time. We started with the year-end 2012 number and just added the 161,000 acres. So this 515 includes all the activities for the year.

Thomas B. Nusz

So, one, there wasn't any other material transactions in there. It was just daily grind and outland work.

Timothy Rezvan - Sterne Agee & Leach Inc., Research Division

Okay. That's helpful. And then just one last one. Can you give a little more kind of big picture overview on exactly what the infrastructure spend in '14 will look like? I know you've guided to $60 million, but are there specific targets you're looking to get in place for the calendar year? Any color would be appreciated.

Michael H. Lou

I think, obviously, a lot of it's going to be around the acquired positions.

Taylor L. Reid

Yes, the infrastructure that we're spending is a continuation of the OMS work that we've been doing. Remember that historically, we've spent capital in the infrastructure side mainly around our saltwater and freshwater distribution systems, and we'll continue that work here this year. On the acquired property, as Tommy mentioned, there is going to be potentially some additional capital that will come on the infrastructure side on that front. We're in the process right now of figuring out -- we kind of talked through the acquisition process that those assets have an ability -- they have less infrastructure currently and as kind of a clean slate in terms of the way we can get move forward on that infrastructure. And so we're still evaluating whether or not we do that third-party or do it in-house. And so there's more to come on that front.

Operator

And your next question comes from the line of Ron Mills with Johnson Rice.

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

Tommy, a couple of questions. Just -- and maybe for Taylor. On the well cost, you talked about going from $7.5 million to $7.3 million. Is that taking into account any incremental implementation of slick water fracs? Or as you move forward, how should we look at how many wells you're using slick water on and the potential impact, not only on well cost, but I assume your commentary was that for the incremental 20% type uplift in cost that you believe that you're seeing more of an uplift than that on EURs to continue to move forward with that?

Taylor L. Reid

So to answer your question, the well cost, incorporating the $7 million to $7.5 million, and both of those numbers have OWS taken out, and so in -- this $7.5 million number has about a $400,000, $450,000 or so OWS impact. Whereas when you look at projection at the end of next year, we're projecting closer to $200,000 per well. So what we've experienced has been that, that number's been higher, but when we just do our projections forward, it's a little more muted. So that's part of it. The other thing is you've got like you talked about the potential for higher stimulation cost, and then there's also a difference in well mix. We've got a little higher percentage of wells that we will drill in the deeper, central part of the basin this year that -- where we have our highest well cost. So that $7.5 million and $7.3 million, those are both average across the whole program. So that's why it didn't look like it's quite a big as drop as you might think it could be. With respect to the slick water, the $1.5 million to $2 million increase, that's based on doing a small number of those wells. We think if they continue to be successful, and it's not in all areas, there's a certain part of the basin where we think it applies. And if they continue to be successful, we think we'll be able to drive that cost down. And when you combine that with, hopefully, what turns out to be a consistent increases in EUR relative to that production increase, we think you'll get improved economics. And so those are all the things we're looking at and weighing and trying to figure out as we do more of these tests.

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

Okay. And then, I think you've mentioned a couple of times that you are only including second bench Three Forks in Indian Hills and South Cottonwood. So I assume that means Bakken, upper Three Forks and second bench in each of those areas. I know early days, but how would that be split amongst the Bakken and the upper and the second bench?

Taylor L. Reid

So we're -- it just depends on where we're drilling the test. But we've got a couple of spacing units that we'll go ahead and drill out, and it'll be split 5 Bakken, 5 first bench and 5 second bench. And then in addition, that's how we split down to the second bench. We have some of those tests, too, where we're actually going to include Three Forks along with it. And so you would have the third bench of the Three Forks along with those that would also have as many as 5 wells. But as we've said, we have not included that in our inventory to this point. We want to do more confirmatory drilling and get a better handle on EUR before we incorporate it.

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

And of those -- I guess I'm trying to just get an idea of, with 60% of your wells being drilled to the Three Forks, of that amount, how many do you think will be used to test multiple benches, whether it be the second bench outside of both Indian Hills and South Cottonwood and/or the third bench across your position, both by yourself? And you have both Cottonwood and on Whiting, and whether it's near your Montana acreage or near your Painted Woods acreage that ongoing tests are going on. So I'm just trying to get a sense of sort of the pace of that potential inventory build.

Taylor L. Reid

Right. Like we talked about, we'll drill 30 lower bench wells, and so second and third. And there's clearly a lot of tests from other operators in and around our position and across the basin. A lot of that in that central area, but there's a number of tests when you -- as you get outside of it. So when we talked about North Cottonwood, and we will drill some additional second bench wells in North Cottonwood this year, and drill those with some drill-outs of spacing units. So we'll drill Bakken, first bench and second bench wells together. With respect to the new areas that we picked up, so Painted Woods, Foreman Butte and even Wild Basin, we're going to have limited drilling in those areas. But we are coring wells in each of those areas, and we'll run high-resolution logs. And then in Wild Basin, we'll drill some lower bench wells. In Painted Woods and Foreman Butte, it will be limited to the first bench for this year. But that -- all that work is to set us up to really start development in those areas in 2015.

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

Okay. And then of the 14 rigs you're running now going to 16 rigs in the second half, how are those currently spread across your position, even if you just want to break it out in the 30 -- or I think you said 34% is in the 7 wells for -- of your DSUs, 40% was in the 10 and the remainder was in the 15 plus. I guess I'm trying to get a sense as to how that rig count is spread across those -- the 3 different breakpoints.

Taylor L. Reid

Sure. So we currently have, just I'll give you east and west and see if we can break them out that way, but there's 9 rigs drilling on the west side and 5 rigs drilling on the east. The weighting that we're looking at with the program for this year is running 4 to 5 rigs on the east side. And that's -- on that side, the south is 15 wells per DSU and the north is 10. And so you're going to flex kind of half and half between probably north and south, but there's going to be periods where a lot of recount is concentrated in that southern part. But 4 or 5 rigs on total in the east. In Indian Hills, where we think of it as the 15 wells per DSU, it's going to be 4 rigs running in that area. In Red Bank, we've got a mix there. On the east side, it's 10 wells per DSU, currently. And on the west side, it's the 7. And it's 4 rigs running in Red Bank, and again, those are going to kind of move around during the year. So you might split that 2 and 2. And then in Montana, you're going to have 2 rigs running. So that gets you to the current 14, and then you'll flex up with the 2 additional rigs. East side, you'll have 1 additional one, and potentially 1 additional in Indian Hills.

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

Okay. And then one last one, just relative barrels sold in terms of the Sanish. I know it was your non-operated asset, but in terms of anything differentiated about those assets, are the production in terms of relative margins to your corporate overall, whether you want to look at on the cash flow or EBITDA margin standpoint?

Michael H. Lou

It's pretty consistent, Ron, with the rest of the [indiscernible].

Operator

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

Dan McSpirit - BMO Capital Markets U.S.

In your press release, you spoke about capital efficiency in 2012 and 2013 by giving us your CapEx and net well completions over those 2 years. What are the comparable CapEx and net well count figures for 2014? Just asking in an effort to get an apples-to-apples comparison.

Michael H. Lou

So D&C capital for '14 will be about $1.25 billion. And the net operated and non-operated well completions will be 155.5 wells. If you do that math, it's about $8 million a well.

Dan McSpirit - BMO Capital Markets U.S.

Right, right. Comparable to what we saw in 2013, if my math is correct. At least, maybe...

Michael H. Lou

Yes, it's comparable to up just a bit. Part of that is the number of rigs that you're increasing kind of at the end of the year. So some of that will actually be carried into next year in terms of completions. You will build your weighting on completion bucket a little bit this year.

Thomas B. Nusz

Addition, the other thing we talked about is you some impact of well mix, more wells being drilled in the more expensive parts of the basin. And then additional cost on stimulation to do a larger percentage of slick water and more expensive type of frac jobs.

Dan McSpirit - BMO Capital Markets U.S.

Got it. And maybe a couple of housekeeping questions here. On the oil differential, the 6% off WTI that's guided, any additional guidance, texture on that how that may -- that average may or that guidance may vary across the -- across 2014? How you have it maybe internally modeled?

Thomas B. Nusz

So the 6% you might be referring to, what we estimate last year on a whole might be for the full year. What we said was the fourth quarter, obviously, was a little bit wider, call it around 12%. It's our expectation. That's going to kind of continue into the first part of this year. However, Clearbrook has started to come back a bit, so first quarter should be a little bit better than fourth quarter. First quarter of this year should be better than fourth quarter of last year. Overall though, we think long-term differentials and we've been saying this for a long time. We think we'll balance out in the 8% to 10% off WTI range on a longer-term basis. We don't know exactly how that will play out short-term kind of month-to-month. The good thing for us is that we have the flexibility to move back and forth to get that best price at any given time.

Dan McSpirit - BMO Capital Markets U.S.

Great. And then the -- maybe the same question or a similar question on -- with respect to the working interest on completed wells over the balance of 2014, how that may change maybe from quarter-to-quarter.

Thomas B. Nusz

Yes, we don't specifically break that out on a quarter-to-quarter basis. Historically, our inventory is kind of built around 68%, 69% average working interest. As we drill, we tend to pick up a little bit more on the interest side so we tend to model just over 70%, so call it 70% to 72-type percent working -- average working interest typically on our growing program.

Dan McSpirit - BMO Capital Markets U.S.

Got it. Great. And then the costs of the second frac spread and maybe how that compares to the first frac spread?

Michael H. Lou

So the cost of the second frac spread is on the order of $20 million and really pretty similar to the cost of the initial spread. You've seen a little bit of reduction in some of the components, but keep in mind that a lot of this equipment is used as transmissions, other heavy equipment that's used in all other lines of manufacturing. It's not just specific to the oil field, and so there's been enough demand in that equipment that you hadn't seen a big drop. So pretty similar in cost.

Operator

And your next question comes from the line of Philip Johnston with Capital One.

Philip Johnston

My question's on the fourth quarter well count. You sort of alluded to this earlier, but it looks like even with the weather impact, you completed in place in your production, 47 gross operated wells during the quarter, which I think was actually above your plan for 44. So I'm just wondering why production won't have comp again towards the low end of the guidance range despite that. Was that -- I mean, was that a function of the timing of those completions within the quarter? Was it a lower working interest on the operated wells or was it...

Thomas B. Nusz

Yes, basically, Philip, it's downtime. And you get weather like that and when these things -- when things go down, it's more difficult to bring them back up. I mean, look at December, I think. Keep in mind, I mean you got base production, all the wells that are on. And then you've got completion activity. And out of, what do we have, 450 plus or minus gross operated wells, there were points in there where we had breadth. I mean it was like 150 wells offline. So at any given day, you may have 30 wells offline, and that's different than wells coming on production.

Operator

And your next question comes from the line of Joseph Stewart with Goldman Sachs.

Joseph B. Stewart - Goldman Sachs Group Inc., Research Division

So, Taylor, you might have partially answered this, but the 400,000 to 600,000 BOE type curves for the Three Forks, is that Three Forks 1 only or does that include the Three Forks 2 and 3?

Taylor L. Reid

I mean, at this point, it's really just an average of what we see in Three Forks. But keep mind, we don't have -- we just don't have a lot of lower bench test. It is early days, so it's intended to be used as an average for Three Forks. As we get more test at the lower benches, we'll update that over time.

Joseph B. Stewart - Goldman Sachs Group Inc., Research Division

Got it. Okay. And then does that 400,000 to 600,000, or the same 450,000 to 750,000 for the Bakken, include any increase in productivity that you talked about for the slick water fracs or other tweaks that you're experimenting with on the completion side?

Taylor L. Reid

No, it's not. It's just our normal completion style.

Thomas B. Nusz

Yes. Keep in mind, Joe, that when we talk about, for instance, slick water jobs performing in the top quartile of the distribution of other wells around it, that's production. Now, we're going to have to see, over time, how that early production translates into EURs. And so how much of it is actually EUR enhancement, how much of it is acceleration. It's early to know that. I mean, we know the daily production numbers, but maybe a bit early to make a firm call on EURs.

Operator

And your last question comes from the line of David Tameron with Wells Fargo Securities.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Just a quick follow-up. On the EURs, are you guys -- what are the reserve engineers allowing you to book now? Or can you give some indication of what you booked as far as locations? And then just as a subset to that, that extends in discoveries, can you talk -- I think it was us 41 or 46, can you talk about what was in that number?

Taylor L. Reid

Okay. So as far as what is booked, and keep in mind, the reserves are -- that we reported are actually done by D&M. So it's their work. In the areas that we talked about where we're using inventory at 15 wells per DSU, so the deeper parts of the basin, they book to the highest density, and that is 3 Bakken and 2 Three Forks wells. The rest of the basin as you go out from there drops off pretty significantly, but on average, it's 2 Bakken and in some cases, 1 Three Forks well, and in some cases, no Three Forks well. So I think a reflection of that is when you look at that PUD count that we talked about earlier, 358 well PUD locations are booked, but inventory of 3,590 or 10% of that total inventory.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Okay. And did you get any additional EUR uplifts from prior years just given the fact that you have a year down the road as far as production data? I was talking about extension discovery in reserve numbers. That's just more [indiscernible].

Taylor L. Reid

So we did -- we had a positive revision and some of that was performance-based. There was a pretty good hunk of that, that was interest-based. So increases in working interest on wells that resulted in revisions from prior years. But there was some performance based off of revisions as well.

Operator

And there are no further questions. And at this time, I would like to turn the call back over to Oasis Petroleum for closing remarks.

Thomas B. Nusz

Thanks, Justin. Our team has spent a significant amount of time planning and evaluating to set the stage for full field development. We're optimizing the long-term development plan of our large concentrated acreage blocks, our infrastructure surface locations and subsurface inventory. The work we've done in 2013 and what we plan to do in 2014 will set our path for years to come and the realization of the significant value growth potential of our asset base. Thank you, again, for providing us the time to share with -- all of that with you today.

Operator

And this does conclude today's conference call. You may now disconnect.

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