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 4th Quarter Operating and Preliminary Financial Results for Oasis Petroleum. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question and answer session.
I will now turn the call over to Michael Liu, Oasis' CFO to begin the conference. Thank you. Mr. Liu, you may begin your conference.
Thank you, Justin. Good morning, everyone. This is Michael Liu. Today, we are announcing 2013 operational and preliminary financial results as well as discussing our operational plans for 2014. We have prepared the summary preliminary financial data based on the most current information available to us.
However, our audit and normal financial reporting process has not been fully completed. As a result, our actual financial results could be different from this summary preliminary financial data and any differences could be material. We intend to release complete 2013 financial results on February 20 5, 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 News and Taylor Reid as well as other members of the team.
Please be advised that our remarks including the answers to your questions include statements that we believe to be forward looking statements within the meaning of the Private Securities Litigation Reform Act. These forward looking statements are subject to risks and uncertainties that could cause actual results to be materially different from those currently disclosed in our 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 ks 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.
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 4th 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, lay out our 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 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 tests around effective down spacing and resource potential in the lower benches of the Three Forks. But not just evaluating the number of wells per drilling spacing unit or DSU, but also the logistics of developing full DSU 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 $40,000,000 less in drilling and completion capital. We're continuing to get more efficient as we've driven our well cost down from $8,500,000 in the Q4 of 2012 to $7,500,000 as we exited this last year, including the impact of OWS. 2nd, we were able to grow our annual production by 51% in 2013 to 33,900 BOEs per day with 4th quarter production of 42,100 BOEs per day.
Our estimated net total proved reserves grew by 50 percent to 227,900,000 barrels, while the PV-ten of our estimated net proved reserves has grown by 69% up to $5,500,000,000 3rd, 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. 4th, we expanded our inventory with tighter down spacing and additional Lower Bench 3 Forch 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.
Thanks, Tommy. In 2013, we focused on the transition to full DSU and field development through evaluation of the Three Forks, infill spacing and optimization of surface operations. The first component we focused on was the 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 Benched Three Forks wells on production.
In Indian Hills, 2 second bench wells, the Paul S and the Patsy as well as a 3rd bench well, the Omelet are performing in line with 3 fourths wells in the area. On the east side, we have also been encouraged by the results of our first two lower bench completions. In South Cottonwood, the Mangum, our first third bench well in the area has been on for 25 days and averaged 9 44 barrels of oil per day in its 1st 7 days and 580 barrels of oil per day since it went on production in spite of flowing at restricted rates since that 1st 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 2nd bench in the area. Keep in mind that well costs in North Cottonwood are generally our lowest at around $6,800,000 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 3rd where we expect to drill 7 wells. The DSUs in the 3 buckets account for 26%, 40% and 34% of our total 403 DSU count respectively. Keep in mind that these counts include 2nd bench wells only in Indian Hills and South Cottonwood and no 3rd 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 a range of 450 to 7 50 MBOEs with a 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 3 fourths range to 400 to 600 with a 500 MBOE midpoint. We are excited about the significant expansion in our inventory and look forward to updating you as we collect more data in the lower bench test and in our interwell 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 Highland 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 count percentage up We will continue to work to get the connected well count percentage up as well as to minimize flared 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 site saves 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 20 14, which will focus on 4 key themes: inventory acceleration, subsurface well density, surface pad operations and cost control and well performance.
1st,
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 4,600,000 and 50000 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 Q1 will fall between 41,045,000 barrels of oil equivalent per day. We will achieve this growth with a total capital expenditure budget of $1,425,000,000 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 leasehold, infrastructure, geology
and equipment
for our 2nd 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 $7,300,000 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 slickwater 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 slickwater completions cost 1.5 $1,000,000 to $2,000,000 more than our typical wells. Given the results, we will perform 15 to 20 more slickwater 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 slickwater, 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. 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 40 2,106 barrels of oil equivalent per day for the Q4. 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 three quarters of 2013, differentials widened out in the 4th quarter to an estimated 12%. Recently, however, 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 Q4. 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've 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 $333,000,000 subject to customary post close adjustments. The divestiture helps delever 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 1st 2 months of the Q1, 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
And your first question comes from the line of Irene Haas with Wunderlich.
Hey, good morning everybody.
Good
morning. So aside from your divestiture of your non op stuff, are there any other sort of assets within your portfolio that could be useful for further debt reduction?
Not at this time, Irene.
Okay. Thanks.
And your next question comes from the line of David Tamarin with Wells Fargo Securities.
Hi. Good morning, everybody. Good morning, Dave. Just strategically, Tommy, how should we think about I guess two questions. 1, did you give us a price that you set your capital budget on for 'fourteen?
And how should we think about how you're looking at the crude curve going forward and some of the backwardation? And is there price sensitivity level where you start to pull back? Or can you just give us
some thoughts around that?
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 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. It seems like the thing is it's 2015 has been 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 in 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%, we 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 costs. 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.
Okay. That's helpful. That's 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 more color what you think the a realistic number is? I'm talking wells per DSU.
Yes. So we are saying on average that it is 10 wells per DSU across the position. But as we highlighted there's areas where it's primarily to the west where the reservoir is thinner, where right now we're saying 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. So when you put all those things together, that's just the current view. As I 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 then also in the lower benches.
We've only included the 2nd bench in Indian Hills and South Cottonwood, and we don't have any 3rd bench included in the inventory currently. So it's based on what we feel comfortable with right now.
Keep in mind, Dave, in a lot of cases with some of the stuff, What we've said consistently is that we like to approach it from one direction and 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've made in some time. And as Taylor mentioned, there may be a little bit more movement on density and we've only included 2nd bench 3 force wells in South Cottonwood and Indian Hills. And so there's no 2nd bench inventory anywhere else and no below 2nd 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.
Okay. And then 3rd and final question. Can you just talk about, Tommy, the rail, I know you guys have had the flexibility to go rail or pipe. Can you talk about your thought unlocking in longer term contracts? And then if you want to comment on anything as far as the rail and regulation, is going to be any impact to you or other players?
And I'll let somebody else jump on.
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 railcar fleet. But we haven't locked in anything on that front yet.
And I think it's 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 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.
And it's been a bit of a strategic move as well, Dave. If you look at the takeaway capacity at call it around 1,500,000 barrels out of the basin right now with production at about 1,000,000 barrels out of the basin a day. There's a lot more takeaway capacity currently and 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 a 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 into some long term takeaway capacity. But until we see a longer term move where takeaway is constrained, we probably won't go to any high percentages of long term agreements anytime soon.
All right. I'll jump off. Thanks.
Thanks, Dave.
And your next question comes from the line of Steve Berman from Canaccord Genuity.
Good morning. Just a couple of questions. Can you tell us what the proved reserves associated with the Sanish divestiture are?
Yes. Hold on, Steve. Just a moment.
As of year end in our press release, we kind of break it out West Williston, East Nesson and Sanish. The Sanish piece is about 8,600,000 barrels are BOE equivalents.
Okay. And the remaining drilling locations, would you happen to have what the PUD component of that is either on a gross or net basis?
Yes. Just So total gross is 358 locations that are PUDs of the 3,590 of remaining inventory.
That's on page 20 of the appendix in the most recently posted we posted it this morning the updated presentation.
All right.
Okay. Great. I'll take a look.
Thanks a lot guys.
You bet.
And your next question comes from the line of Drew Venker with Morgan Stanley.
Good morning, guys. I was hoping you could discuss where your production is currently and if you feel you've fully recovered from the winter weather or if there's still some production that has to come back online?
As we talked about in starting really in late November, we 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, the number of frac jobs we can get completed. As we came into January, you had a pretty good warm up in the 1st 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 a 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 impacts probably not as severe as we saw in December because I think we're past those just extreme cold conditions.
Okay. And then in regards to the oil differentials, the those reports out that the winding refinery is switching over to running heavy. Do you expect that to have any meaningful impact on pricing for you guys?
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.
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%.
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.
Lastly, just curious on service costs, if you're seeing improvements in day rates or completion costs, if there's any change to your year end 2014 well cost target?
We really haven't seen a lot of movement in 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. Okay.
Thanks for the color.
Thanks.
And your next question comes from the line of Michael Hall with Heikkinen Energy Advisors.
Thanks. Good morning.
Hey, Michael.
Let's see. I guess, wanted to drill in a little bit on the EUR commentary and guidance particularly around 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 bias in the 2014 program in terms of where you're drilling Three Forks relative to that range provided?
So 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 3 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 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, 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 3 Forks wells. With respect to the lower benches, 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.
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 3.4s. There's no variability between how much reduction you're seeing?
That 15% may vary a bit, but what you just said is right. Okay. But we felt like it was important to provide a little bit more granularity on the 3.4s given the magnitude that it plays and what the total program. As Taylor mentioned, it will be 60% of roughly 60% of the wells drilled for this year and then a fair amount is lower benches. So we felt like that from a modeling standpoint, it was important to kind of communicate that.
Certainly. That makes sense. And then I guess along those lines on EUR, I'm just trying to think about you're doing a lot of down spacing testing as well. Have you seen any degradation in EUR as you've worked through the down spacing? I mean, you kept your middle Bakken EUR range constant.
Just trying to understand what you're seeing there. And is there any kind of risking to that that's implicit in the guide given how much down spacing and work you're doing in 2014?
So with respect to degradation in the EURs, 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. It 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 or ready to talk about that yet.
We're still doing work on it.
Fair enough. Makes sense. I appreciate the color. And then I guess last on or I guess 2 on mine. One more is just both on costs.
First, any can you give us a future development cost associated in that PV-ten provided? I don't know if I missed it. And then second was on the LOE and OpEx guidance, should we think about that? Is it kind of linear from the Q4 of 2013 to Q4 2014, if we kind of think about the front end being highest or just trying to think about how to shape that throughout the year?
Okay. So the total capital in that PB10 number is $1,880,000,000 a little over that.
Okay.
And then with respect to the LOE, you're going to see relative to what it was in the Q4 because we closed on the acquisitions at beginning of October. So you got full impact of the LOE and the LOE on the acquired properties 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 winter weather, probably not a lot and especially a winter like this. And more likely in Q2 and 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 down trend.
Okay. Appreciate it. Thanks guys.
Hi Michael. Thanks.
And your next question comes from the line of Dan Braziler from Jefferies.
Hi, guys. Thanks for taking my question.
You bet. I was
just wondering what 4Q CapEx was and if some of that spend got pushed into 2014 and if that was due to weather? Thanks.
Yes. Hold on. I think obviously we did have a little bit that got pushed. That being said, we still completed brought on production 47 wells.
Yes. Tommy, we from a drilling standpoint, we got we didn't have a lot of problems with the rigs, a little bit on move. It was mostly around the completion side of the business. So a little bit got pushed, but not gigantic together.
Yes. So the $240,000,000 or thereabouts that will be spent was spent in the 4th quarter. Most of that cost savings though was because of being more efficient. And so through the year, we spent around $50,000,000 $60,000,000 less than budget.
And
most of 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 winter period. There are some wells that kind of come forward, but overall it's pretty much a wash.
Okay. Thanks.
You bet.
And your next question comes from the line of Tim Rezvan from Stern Gerken.
Hi. Good morning, folks. Had a quick one. Looking at your net acreage position about $515,000 it looks like from the deals announced in September you 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?
Yes. We spent on land about $25,000,000 And so with those land expenditures, we were able to increase our acreage position. And And in addition to that, we had some top leases take effect and some other consolidation of positions through trades. And 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 $515,000 includes all the activity for the year.
Yes. So there wasn't any other material transactions in there. It was just daily grinded out land work.
Okay. That's helpful. Thank you. And then just one last one. Can you give a little more kind of big picture overview on exactly what the infrastructure spend in 2014 will look like?
I know you've guided to $60,000,000 but are there specific targets you're looking to get in place for the calendar year? Any color would be appreciated. Thanks.
I think, obviously, a lot of it's going to be around the
acquired physicians. 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 on the infrastructure side mainly around our saltwater and fresh water 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've kind of talked through the acquisition process that those assets have an ability they have less infrastructure currently and kind of a clean slate in terms of the way we can move forward on that infrastructure. So we're still evaluating whether or not we do that 3rd party or do it in house. And so there's more to come on that front.
Okay. Thank you.
And your next question comes from the line of Ron Mills with Johnson Rice. Good morning, Tommy.
Hey, Ron.
A couple of questions just and maybe for Taylor. On the well costs, you talked about going from $7,500,000 to 7,300,000 dollars Is that taking into account any incremental implementation of slickwater fracs? Or as you move forward, how should we look at how many wells you're using slickwater 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?
So Sean, good question. The well cost incorporated in 7.5% and both of those numbers have OWS taken out. And so in 2,000 this $7,500,000 number has about $400,000 $450,000 or so of 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 has 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 costs. So that 7.5% and 7.3% those are both average across the whole program. So that's why it doesn't look like it's quite a biggest drop as you might think it could be.
With respect to the slickwater, the $1,500,000 to $2,000,000 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 increase 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.
Okay. And then I think you've mentioned a couple of times that you are only including 2nd bench 3 Forks in Indian Hills and South Cottonwood. So I assume that means Bakken Upper Three Forks and 2nd 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?
Yes. 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 will be split 5 Bakken, 5 1st bench and 5 2nd bench. And then in addition, that's how we split down to the 2nd bench. We have some of those tests who are actually going to include 3 forks along with it. And so you would have 3rd benches of 3 Forks along with those that would also have as many as 5 wells.
But as we 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 the EURs before we incorporate it.
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 2nd bench outside of both Indian Hills and South Clinton Wood and or the 3rd bench across your position, both by yourself and you have both Continental and 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 as to the pace of that potential inventory build.
Well, like we talked about, we'll drill 30 lower bench wells. And so 2nd 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 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 1st bench and 2nd 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 Forman Butte and
it will be
limited to the 1st bench for this year. But that's all that work is to set us up to really start development in those areas in 2015.
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 per 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? 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 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 wheat count concentrated in that southern part, but 4 to 5 rig in 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. That gets you to the current 14 and then you'll flex up with the 2 additional rigs. Eastside, you'll have one additional and one and potentially one additional in Indian Hills.
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 or the production in terms of relative margins to your corporate overall, whether you want to look at on the cash flow EBITDA margin standpoint?
It's pretty consistent Ron with the rest of the business.
All right. Let me let someone else jump in. Thank you guys.
Thanks Rod.
And your next question comes from the line of Dan McSpirit from BMO Capital Markets.
Thank you, folks. Good morning.
Good morning.
In your press release,
you spoke about capital efficiency in 20122013 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.
So D and C capital for 2014 will be about 1,250,000,000 dollars and the net operated and non operated well completions will be 155.5 wells. So if you do that math, it's about $8,000,000 a well.
Right, right. Comparable to what we saw in 2013, if my math is correct
or at least maybe 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 waiting on completion bucket a little bit this year.
Got it. And then go ahead.
In addition, the other thing we talked about is you had some impact of well mix, more wells being drilled in more expensive parts of the basin. And then additional cost on stimulation to do a larger percentage of slickwater and more expensive type of frac jobs.
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 how that may that average may or that guidance may vary across 2014? How you have it maybe internally modeled?
So the 6% you might be referring to what we estimate last year on
a whole might be For the full year.
For the full year. What we said was the Q4 obviously was a little bit wider call it around 12% is our expectation. That's going to kind of continue into the 1st part of this year. However, Clearbrook has started to come back a bit. So Q1 should be a little bit better than Q4.
Q1 of this year should be better than Q4 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 that 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.
Great. And then the maybe same question or 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?
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 average working interest typically on our drilling program.
Got it. Great. And then the cost of the second frac spread and maybe how that compares to the first frac spread?
So the cost of the 2nd frac spread is on the order of $20,000,000 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 that's used is transmissions, other heavy equipment that's used in all other lines of manufacturing. It's not just specific to the oilfield. And so there's been enough demand in that equipment that you hadn't seen a big drop.
So pretty similar in cost.
Got it. Thanks again.
You bet.
And your next question comes from the line of Phillips Johnston with Capital One.
Hey, guys. Thanks. My question is on the Q4 well count. You sort of alluded to this earlier, but it looks like even with the weather impact you completed and placed in a production 47 gross operated wells during the quarter, which I think was actually above your plan for 44. So I was just wondering why production wound up coming in towards the low end of the guidance range despite that.
Was that I mean was it a function of the timing of those completions within the quarter? Was it a lower working interest on the operated wells? Or was it Yeah.
I mean basically Phillips it's downtime. And you get weather like that and when these things go down it's more difficult to bring them back up. I mean Okay. It's December and keep in mind, I mean, you've 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, Brett, I mean it was like 150 wells offline.
Okay. So on any given day you may have a third of your wells offline. And that's different than wells coming off production.
Sure.
Okay. Thank you. You bet.
And your next question comes from the line of Joseph Stewart with Goldman Sachs.
Good morning. Thank you everybody.
You bet.
So, Taylor, you might have partially answered this, but the 400,000 to 600,000 BOE type curve for the Three Forks, is that Three Forks 1 only or does that include the Three Forks 2 and 3?
Mean, at this point, it's really just an average of what we see in Three Forks. But keep in 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 3, forks. As we get more test
at the
lower benches, we'll update that over time.
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 slickwater fracs or other tweaks that you're experimenting with on the completion side?
No, it does not. It's just our normal completion style. Yes. Okay.
Yes. Keep in mind Joe that when we talk about for instance Slickwater 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?
Right, right.
It's early to know. I mean we know the daily production numbers, but maybe a bit early to make a firm call on the EURs.
Sure. Okay. Well, thanks guys. All my other questions have been answered. Thank you.
Thanks, Joe.
And your last question comes from the line of David Tamarin with Wells Fargo Securities.
Hi. 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 of that, that Extensions Discoveries, can you I think it was 41 or 46.
Can you talk about what was in that number?
Okay. So as far as what is booked, keep in mind the reserves are that we report are actually done by D and M. So it's their work. In the areas that we talked about where we're using inventory of 15 wells per DSU, so the deeper parts of the basin, they've booked to the highest density and that is 3 Bakken and 2 3 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 3 Forks well and in some cases no 3 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 of an inventory of 3,590 or 10% of that total inventory.
Okay. Okay. And did you get any additional EUR uplifts from prior years just given the fact you have a year down the road as far as production data? I was looking at that extension discovery and reserve numbers, is that just more
Yes. 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 upper revisions as well.
Okay. I can get more detail offline. Thanks guys. I appreciate it.
Thanks, Dave.
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.
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.
And this does conclude today's conference call. You may now disconnect.