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. All lines have been placed on mute to prevent any background noise. After the speaker's remarks, there will be a question and answer session. I will now turn the call over to Michael Lou, Oasis CFO, to begin the conference. Thank you. Mr. Lou, you may begin your conference.
Thank you, 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 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 25th, 2014. This call will take the place of the call that we have historically done around our earnings release. I'm joined today by Thomas Nusz and Taylor Reid, as well as other members of the team.
Please be advised that our remarks, including the answers to your questions, include statements that we believe to be forward-looking statements within the meaning of the Private Securities Litigation Reform Act. These forward-looking statements are subject to risks and uncertainties that could cause actual results to be materially different from those currently disclosed in our 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 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 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 from 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 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. Not just evaluating the number of wells per 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 four 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. In 2013, we had four key accomplishments that I would like to draw your attention to.
First, we were able to complete 136 gross operated wells, which was eight 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 last year, including the impact of OWS. Second, we were able to grow our annual production by 51% in 2013, to 33.9 thousand BOEs per day, with fourth quarter production of 42.1 thousand BOEs per day. Our estimated net total proved reserves 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.
Thanks, Tommy. In 2013, we focused on the transition to full DSU and field development 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 seven 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 five lower bench Three Forks wells on production. In Indian Hills, two second bench wells, the Paul S and the Patsy, as well as a third bench well, the Omelet, 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 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 944 barrels of oil per day in its first seven 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 five 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, as a result, leads us to be optimistic about the second bench in the area.
Keep in mind that well costs 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, 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 three 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, the third where we expect to drill seven wells. The DSUs in the three 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, no third bench wells in any area. As Tommy mentioned, we now count 3,590 wells in our drilling inventory, 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 450-750 MBOE 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 Three Forks range to 400-600 with a 500 MBOE midpoint. We are excited about the significant expansion in our inventory, 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 Hiland Partners. Our newly acquired assets are not quite as mature with respect to infrastructure as our legacy assets, we see a lot of opportunity to build out the infrastructure and improve margins.
On the gas 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 flared gas. On the water front, 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 2014, which will focus on four 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 two 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 back-loaded 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 leasehold, 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%-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 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 million-$2 million more than our typical wells. Given the results, we will perform 15-20 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. 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 three quarters of 2013, differentials widened out in the fourth quarter to an estimated 12%. Recently, however, Clearbrook differentials have tightened up to WTI, 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 a 8%-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, we are expecting 2014 LOE per BOE to be higher than we've experienced in 2013. 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, it will take us approximately six 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 two 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.
At this time, if you would like to ask a question, you may do so by pressing star then the number one on your telephone keypad. Once again, that is star then the number one. We will pause for just a moment to compile the Q&A roster. Your first question comes from the line of Irene Haas with Wunderlich.
Oh, yay. Good morning, everybody. Morning. 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.
Your next question comes from the line of David Tameron with Wells Fargo Securities.
Hi. Morning, everybody.
Morning, David Tameron.
Just strategically, Thomas Nusz, how should we think about I guess two questions. One, did you give us a price that you set your capital budget on for 2014? How should we think about how you're looking at the crude curve going forward and some of the backwardation and is there a price sensitivity level where you start to pull back? Can you just give us some thoughts around that?
This year, the base budget is $85-$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-$85. You kind of look at the curve for actuals for the last three years, and based on that, we felt like it made sense to bump it up just a bit to be true to ourselves. 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 staying backwardated, but it's just moving forward. In fact, I think it's up a bit today, but 2015 has been kind of anchored, but then more recently moved down a little bit.
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. As a practical matter, as we've said for some time, as we start to see visibility down around $70 to $75, but 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. Keep in mind that too is based on current well costs.
As we go down, if we do, to call it $50 to $60, we've 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 six or seven rigs, in that low price environment, kind of tread water on volumes and live within cash flow. That's basically how we look at it.
Okay. That's helpful. Yeah, it's good color. How should I think about the DSUs? 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 realistic number is? I'm talking wells per DSU.
Yeah. We're saying on average that it is 10 wells per DSU across the position. 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 seven wells. 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. In the east side, in the north, we think it's 10 wells there. It depends on where you are in our position. That's based on all the work that we've done with respect to the down-spacing test, oil in place, the amount of drainage that we expect, and then modeling. 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. It's based on what we feel comfortable with right now. Keep in mind, Dave, in a lot of cases with some of this stuff, what we've said consistently is that we like to approach it from one direction, and inventory is no different. As we gather more data, we like to step in an orderly manner upwards and give you an at least as, for lack of a better term, number. This is the first step that we've made in some time. As Taylor mentioned-
There may be a little bit more movement on density, and we've only included second bench Three Forks wells in South Cottonwood and Indian Hills. There's no second bench inventory anywhere else and no below second bench inventory in any of the asset positions. 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. Third 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 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.
Yeah. I'll let Michael add to it, but I think 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 rail car fleet. We haven't locked in anything on that front yet. I think this thing has evolved so quickly over the last 18 months. There really hasn't been a whole lot of option to do a lot of longer term stuff at what we consider to be reasonable prices. We'll keep watching that. Michael may have a bit more to add on that.
It's been a bit of a strategic move as well, Dave. If you look at the takeaway capacity at called 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 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. We've got a great gathering system. 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 shorter term type positions.
As our production continues to grow, we will start locking into some long-term takeaway capacity. 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.
Your next question comes from the line of Stephen 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?
Yeah, hold on, Steve.
Just a moment. As of year-end, in our press release, we break it out West Williston, East Nesson, and Sanish. The Sanish piece is about 8.6 million barrels or BOE equivalents.
Okay. The remaining drilling locations, would you happen to have what the PUD component of that is, either on a gross or net basis?
Yeah. Just 358. This is a little hard. Just a moment. Total gross is 358 locations that are PUDs of the 3,590 of remaining inventory.
That's on page 20.
Page 20 of the appendix in the most recently posted, we posted it this morning, the updated presentation.
All right.
You can find it in there.
Okay. Great. I'll take a look. Thanks a lot, guys.
You bet.
Your next question comes from the line of Drew Venker with Morgan Stanley.
Morning, guys. I was hoping you could discuss where your production is at 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, starting really in late November, had severe cold snap that went through most of December, a lot of 20 to 30 degree below zero weather. 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 frac jobs we can get completed. As we came into January, you had a pretty good warm-up in the first couple of weeks, the ability to get a lot of that production back on, not all of it, but really get production back up, now we're back into a storm track that's hitting regularly, but not as severely cold as in December.
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. In regards to the oil differentials, there's 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?
Yeah, I think we did see a bit of that impact already, differentials have closed back, as refineries move over to heavies, obviously there is some impact to the light suite in that area.
Okay. It sounds like you're not thinking it's all that significant because your differential guidances long term is where you had it before, I think 8%-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. 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.
Yeah, thanks.
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 help us think about how that Three Forks EUR 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 that range provided?
That range across the position mimics what we've discussed in the Bakken previously. The highest EURs you're going to see in the Three Forks are in the more central, deeper part of the basin. 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. 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 Three 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, in South Cottonwood, but also drilling some additional lower bench wells in North Cottonwood.
Okay. That's helpful. The 15%, 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're seeing?
That 15% may vary a bit, but what you just said is right.
Okay.
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 will be roughly 60% of the wells drilled for this year, and then a fair amount is lower benches. We felt like that from a modeling standpoint, it was important to communicate that.
No, certainly. It makes sense. I guess along those lines on EUR, I am just trying to think about, you are doing a lot of down-spacing testing as well. Have you seen any degradation in EUR as you have worked through the down-spacing? Have you kept your middle Bakken EUR range constant? I am just trying to understand what you are seeing there, then is there any kind of risking to that that is implicit in the guide, given how much down-spacing work you are doing in 2014?
With respect to degradation in the EURs, that is something we are working on. When you look at the spacing tests, most of those being in early time, a year or less, you do not 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. At this point, we are just not in a position or ready to talk about that yet. We are still doing work on it.
Fair enough. Makes sense. I appreciate the color. I guess last, or I guess two on my end. One more is just both on cost. First, can you give us a future development cost associated in that PV-10 provided? I do not know if I missed it. Second was on the LOE and OpEx guidance, as we think about that, is it linear from the fourth quarter of 2013 to fourth quarter 2014? If we think about the front end being the highest, or just trying to think about how to shape that throughout the year.
Okay.
That's all I got.
The total capital in that PV-10 number is $1.88 billion, a little over that.
Okay.
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 at beginning of October, you got full impact of the LOE. The LOE on the acquired properties is quite a bit higher than our existing LOE. 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, especially a winter like this. More likely in 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.
Okay. Appreciate it. Thanks, guys.
Bye, Michael. Thanks.
Your next question comes from the line of Dan Braziller from Jefferies.
Hey, 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.
Yeah. 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. Yeah. Tommy, from a drilling standpoint, 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, a little bit got pushed, not gigantic to get it.
Yeah. 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. Through the year, we spent around $50 million, $60 million less than budget.
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've budgeted. We did get some work done even through that winter period. There are some wells that come forward, but overall, it's pretty much a wash.
Okay, thanks.
You bet.
Your next question comes from the line of Tim Rezvan from Sterne Agee.
Good morning, folks. Had a quick one. Looking at your net acreage position, about 515, 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 give a little color on that increase?
Yeah. We spent on land about $25 million. With those land expenditures, we were able to increase our acreage position. In addition to that, we had some top leases take effect and some other consolidation of positions through trades. When you put all that together, it's just 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. This 515 includes all the activity for the year. Yeah. There wasn't any other material transactions in there. It was just daily grinded out land work. Yeah.
Okay. That's helpful. Thank you. Just one last one. Can you give a little more big picture overview on exactly what the infrastructure spend in 2014 will look like? I know you've guided to $60 million, 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 positions.
Yeah. 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 freshwater distribution systems. We'll continue that work here this year. On the acquired property, as Tommy Nusz 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 talked through the acquisition process that those assets have less infrastructure currently, and it's a clean slate in terms of the way we can move forward on that infrastructure. We're still evaluating whether or not we do that third party or do it in-house. There's more to come on that front.
Okay. Thank you.
Your next question comes from the line of Ron Mills with Johnson Rice & Company.
Morning, Tommy Nusz.
Hey, Ron.
A couple questions, and maybe for Taylor. On the well cost, you talk about going from $7.5 million to $7.3 million. Is that taking into account any incremental implementation of slickwater fracs? 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?
Yep. Ron, good question. The well cost, incorporating the $7.5, and both of those numbers have OWS taken out. In this $7.5 million number has about $400,000, $450 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. 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. 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, where we have our highest well cost.
That $7.5 and $7.3, those are both average across the whole program. That's why it doesn't look like it's quite as big a drop as you might think it could be. With respect to the slickwater, the $1.5 million-$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. If they continue to be successful, we think we'll be able to drive that cost down. 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.
those are all the things we're looking at and weighing in and trying to figure out as we do more of these tests.
I think you've mentioned a couple of times that you are only including Second Bench Three Forks in Indian Hills and South Cottonwood. 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?
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 five Bakken, five first bench, and five second bench. In addition, that's how it'll be split down through the second bench. We have some of those tests, too, we're actually going to include Three Forks along with it. You would have third bench of the Three Forks along with those that would also have as many as five wells. 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.
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 Continental and Whiting and Whether it's near your Montana acreage or near your Painted Woods acreage that ongoing tests are going on.
Sure.
I'm just trying to get a sense as to the pace of
Yeah
of that potential inventory build.
Right. Like we talked about, we'll drill 30 lower bench wells, and so second and third. There's clearly a lot of tests from other operators in and around our position and across the Bakken. A lot of that in that central area, but there's a number of tests as you get outside of it. We talked about North Cottonwood, and we will drill some additional second bench wells in North Cottonwood this year. Drill those with some drill outs of spacing units. We'll drill Bakken first bench and second bench wells together. With respect to the new areas that we've picked up, so Painted Woods, Foreman Butte, and even Wild Basin, we're going to have limited drilling in those areas. 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'll be limited to the first bench for this year. All that work is to set us up to really start development in those areas in 2015.
Okay. 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.
Yep.
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 the three different break points.
Sure. We currently have Just, I'll give you East and West and see if we can break them out that way.
Yeah
There's nine rigs drilling on the west side and five rigs drilling on the east. The weighting that we're looking at with the program for this year is running four to five rigs on the east side. On that side, the south is 15 wells per DSU and the north is 10. You're going to flex half and half between probably north and south, but there's going to be periods where a lot of it will be concentrated in that southern part. Four to five rigs in total in the east. Indian Hills, where we think of it as the 15 wells per DSU, it's going to be four rigs running in that area. Red Bank, we've got a mix there.
On the east side, it's 10 wells per DSU currently, on the west side, it's the seven, and it's four rigs running in Red Bank. Again, those are going to move around during the year, so you might split that two and two. In Montana, you're going to have two rigs running. That gets you to the current 14, then you'll flex up with the two additional rigs. East side, you'll have one additional and one, and potentially one additional in Indian Hills.
Okay. 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 it on the cash flow or EBITDA margin standpoint?
It's pretty consistent, Ron-
Okay
with the rest of the business.
All right. Let someone else jump in. Thank you, guys.
Thanks, Ron.
Your next question comes from the line of Dan McSpirit from BMO Capital Markets.
Thank you, folks. Good morning.
Morning.
In your press release, you spoke about capital efficiency in 2012 and 2013 by giving us your CapEx and net well completions over those two 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.
Dave, go ahead.
D&C capital for 2014 will be about $1.25 billion. 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.
Right. Comparable to what we saw in 2013, if my math is correct, or at least.
Yeah. It's comparable to up just a bit.
Part of that is the number of rigs that you're increasing at the end of the year.
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. Go ahead.
In addition, the other thing we talked about is you have some impact of well mix, more wells being drilled in the more expensive parts of the basin. Additional cost on stimulation to do a larger percentage of slickwater and more expensive type of frac jobs.
Got it. Maybe two housekeeping questions here. On the oil differential, the 6% off WTI that's guided, any additional guidance texture on how that average may or that guidance may vary across 2014? How you have it maybe internally modeled?
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 fourth quarter obviously was a little bit wider, call it around 12%.
is our expectation. That's going to continue into the first part of this year. Clearbrook has started to come back a bit. First quarter should be a little bit better than fourth quarter.
Right.
First quarter of this year should be better than fourth quarter of last year. Though, we think long-term differentials, and we've been saying this for a long time, we think will balance out in that 8%-10% off WTI range on a longer-term basis. We don't know exactly how that'll play out short-term, 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. Then maybe the same question or a similar question with respect to the working interest on completed wells over the balance of 2014, how that may change maybe from quarter to quarter.
Yeah. We don't specifically break that down on a quarter-to-quarter basis. Historically, our inventory is built around 68%, 69% average working interest. As we drill, we tend to pick up a little bit more on the interest side, we tend to model just over 70%. Call it 70%-72%-type average working interest typically on our drilling program.
Got it. Great. The cost of the second frac spread and maybe how that compares to the first frac spread?
The cost of the second frac spread is on the order of $20 million. Really pretty similar to the cost of the initial spread. You've seen a little bit of reduction in some of the components, 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 oil field, there's been enough demand in that equipment that you haven't seen a big drop. Pretty similar in cost.
Got it. Thanks again.
You bet.
Your next question comes from the line of Phillips Johnston with Capital One.
Hey, guys. Thanks. My question is on the fourth quarter well count. You sort of alluded to this earlier, but it looks like even with the weather impact, you completed and placed into production 47 gross operated wells during the quarter, which I think was actually above your plan for 44.
Right
I'm just wondering why production wound up coming in towards the lower end of the guidance range despite that. 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?
Basically, Phillips, it's downtime. You get weather like that, and when these things go down, it's more difficult to bring them back up.
Okay.
December, keep in mind, you got base production, all the wells that are on, then you've got completion activity. Out of, what do we have, 450 plus or minus gross operated wells, there were points in there where we had, Brett, it was like 150 wells offline.
Okay.
On any given day, you may have 30 wells offline. That's different than wells coming on production.
Sure. Okay. Thank you.
You bet.
Your next question comes from the line of Joseph Stewart with Goldman Sachs.
Good morning. Thank you, everybody.
You bet.
Taylor, you might have partially answered this, but the 400,000-600,000 BOE type curve for the Three Forks, is that Three Forks 1 only, or does that include the Three Forks 2 and 3?
At this point, it's really just an average of what we see in Three Forks, but keep in mind, we just don't have a lot of lower bench tests. It is early days, so it's intended to be used as an average for Three Forks. As we get more tests to the lower benches, we'll update that over time.
Got it. Okay. Does that 400,000-600,000 or the same 450,000-750,000 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.
Yep. Okay.
Yeah. 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. We're going to have to see over time how that early production translates into EURs, how much of it is actually EUR enhancement, how much of it is acceleration?
Right. Okay.
It's early to know. We know the daily production numbers, maybe a bit early to make a firm call on EURs.
Sure. Okay. Well, thanks, guys. All my other questions have been answered. Thank you.
Thanks, Joe.
Your last question comes from the line of David Tameron with Wells Fargo Securities.
Just a quick follow-up. On the EURs, what are the reserve engineers allowing you to book now? Can you give some indication of what you booked as far as locations? Just as a subset of that extension discoveries, I think it was 41 or 46. Can you talk about what was in that number?
As far as what is booked, and keep in mind, the reserves that we report are actually done by DNM, it's their work. In the areas that we talked about, where we're using inventory of 15 wells per DSU, the deeper parts of the basin, they book to the highest density, and that is three Bakken and two Three Forks wells.
Okay.
The rest of the basin, as you go out from there, drops off pretty significantly, but on average, it's two Bakken, and in some cases, one Three Forks well, and in some cases, no Three Forks wells. 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.
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. That's just more duplications.
We had a positive revision, some of that was performance based. There was a pretty good hunk of that that was interest based, increases in working interest on wells that resulted in revisions from prior years. There was some performance-based upward revisions as well.
Okay. I can get more detail off-line. Thanks, guys. I appreciate it.
Yeah. Good luck.
Thanks, Dave.
There are no further questions. 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 all of that with you today.
This does conclude today's conference call. You may now disconnect.