Good morning. My name is Celeste, and I will be your conference operator today. At this time, I would like to welcome everyone to the 4th quarter year end twenty ten earnings release and Operations Update for Oasis Petroleum. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question and answer session.
I would now like to turn today's call over to Mr. Liu. Sir, you may begin your conference.
Thank you, Celeste. Good morning, everyone. This is Michael Luz, Senior Vice President, Finance. We're reporting our Q4 year ending December 30 one, 2010 results today, and we're glad to have you join our call. With me today from Oasis are Tommy News, President and Chief Executive Officer Taylor Reid, Chief Operating Officer Roy Mace, Chief Accounting Officer and Richard Robuck, Director of Investor Relations.
This call is being recorded and will be available for replay approximately 1 hour after its completion. The conference call replay and our earnings release are available on our website at www.oasispetroleum.com. In addition, we have updated our investor presentation for the financial and operational results, which is on our website. Although we will not be speaking off the slides during this call, please feel free to refer to it for clarification. Please be advised that our following 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 anticipated. Those risks include, among others, matters that we have described in our earnings release as well as in our filings with the Securities and Exchange Commission, including our Form S-one and as amended. We disclaim any obligation to update these forward looking statements. Please note that our 20 10 Form 10 ks will be filed tomorrow. During this conference call, we will also make references to adjusted EBITDA, which is a non GAAP financial measure.
Reconciliations of adjusted EBITDA to the bookable GAAP measures can be found in our earnings release or on our Web site. I'll turn the call over to Tommy.
Good morning, everyone, and thanks, Michael. First, I'd like to thank everyone for joining us this morning. I think it's fair to say that we have plenty to celebrate here at Oasis as it relates to the year 20 10 as we ended the year with very impressive results including a successful IPO. I'm very proud of the team that we've put together and what we've able to accomplish. I'm also confident that they're ready to take on the challenges ahead in 2011 as we continue to increase activity and focus on the drivers of value.
You've had much of our year end data now for over a month and as you know, we don't see much need in reading our press releases to you. So we'll try to focus this call on the high points for 20 10 and the outlook for 2011. I will cover operations first and we'll let Michael finish up with our financial conversation. We set out at the beginning of 2010 to establish our drilling program in the Williston Basin in order to grow production and reserves. We definitely achieved that in what we set out to do as we grew from 2 2009 to 6 rigs at the end of 2010.
We have another rig showing up in the Williston around the end of this month, which will give us 6 rigs in the West and 1 rig in the East. We grew production to 7,511 BOEs per day in the 4th quarter and ended the year with reserve of 39.8 millimeters millimeters millimeters millimeters millimeters millimeters millimeters millimeters millimeters millimeters Boe. We also completed 2 strategic bolt on acquisitions in Montana that we're very excited about and we'll give you some more color on what we're seeing there in this area, which we call Hebron in a minute. When we started Oasis in 2,007, we had a clear focus on oil and we've been rewarded for this decision throughout 2010 and into 2011 as our oil weighted continues to deliver substantially better margins than natural gas production. Since our inception, our team has accumulated over 300,000 net acres in the Williston Basin.
And since we got an early start coupled with doing some opportunistic acquisitions in the 2,009 down cycle, our average acreage cost is very low and our acres are well positioned. Having this large position in place allows us to direct a large portion of our CapEx to the drill bit. We drilled, completed and placed on production 26 operated wells in 2010. And as of March 1, we have 21 operated wells in the West and 12 operated wells in the east on production from our latest drilling program that started in late 2009. We invested $243,800,000 or 70 percent of our CapEx in development throughout 2010.
Since 45% of our production in the Q4 of 2010 and 70% of our CapEx for the year was associated with our West Williston project area. I will focus on the results there first. As you all know, we have set type curves in the West Williston at 400,000 to 700,000 barrels only. We continue to see our wells come into this range. And as we mentioned in our August call, our Angel well had been performing on or above the top end of the type curve range and is still performing around the upper end of the type curves.
We call the area around the Angel Well Indian Hills. This area represents the deepest part of the basin and has comparatively higher reservoir pressure and also a higher hydrocarbon core volume. We currently have 4 wells producing in this area, all of which have EURs towards the upper end of our type curve range. So we're very pleased with that. We have about 20 1,000 acres in the block and budgeted about 20% of our 2011 drilling plan in Indian Hills.
Our largest block of land is in an area we call Red Bank, where we have approximately 63,000 acres and currently have 14 wells in the area. This is our northern block in Williams County. We completed 12 of the 14 wells on pads, which definitely helps our cost structure and efficiency. We are basically able to drill 1 well north and 1 well south off of the same pad and adjacent 12 80 acre drill blocks. If the wells are being drilled back to back, the rig can easily skid from 1 to the next.
And as you've heard us talk about before, this setup also helps the completion process as we can pump 1 frac stage on one well while we set the plug and perforate on the other. Lastly, the way we have our pads configured, we can run gas, oil and water pipelines right through the pads. And as you look at our maps, we have quite a few straight lines running through this Red Bank area, meaning we have set up our drilling locations so that over the long run, we can run our operations just like a manufacturing process. Given the well results to date, the operating efficiency that we have in this large contiguous block and the protection of our lease position, 42% of our drilling budget in 2011 will be in the Red Bank block. Wells in Red Bank are not quite as prolific as the wells in Indian Hills, but are clearly within our original expectations and look very good nonetheless.
Red Bank is shallower than Indian Hills and therefore has a little less reservoir and we estimate a slightly lower hydrocarbon core volume. So the fact that they are lower in our type curve range makes a lot of sense to us. Now let's move over to the block in Richland and Roosevelt Counties in Montana, in the area that we generally call Hebron and adjacent to it, Missouri, where we picked up about 27,000 acres in the 4th quarter and now have a total of 57,000 net acres combined. We have 3 operated wells that are currently producing that were drilled by the previous operator and completed in a manner similar to what we do but with less stages. Those wells are the Luke Sweetman on the south central portion of the block, the Amazing Grace on the east side of the block along the state line and the Beulah Irene on the west side of the block about 10 to 12 miles from the Amazing Grace.
While the Beulah Irene was drilled and set up by the previous operator, we actually at Oasis completed it after the acquisition. We now have 2 other operated wells, the Mary Wilson and the Wilson that we have drilled on the Montana side of our block and we're waiting on completion as of March 1. These wells are both set up as 28 stage completions and one of the wells, the Wilson will be completed in the Free Forks. We are very pleased to have the Beulah Irene, our furthest West Middle Bakken completion, produced in line with the amazing Grace well, which as I mentioned is on the east side right on the state line. Based on early production data, we are very comfortable that the area between these two wells will have similar results.
And given these wells look to be within our type curve ranges with 23 stages, we are very excited about the potential to be realized with 28 to 30 6 stage jobs across the Hebron block. We will basically run 1 operated rig in Hebron throughout 2011. We also have 2 wells waiting on completion just across the state line in North Dakota and one of those, the Moore is a Three Forks completion. So we should have 2 good Three Forks tests on our data over the next two quarters. We also expect to drill a Three Forks test in all of the existing West Williston project areas over on the West Williston project areas by year end.
Again, we'll keep you posted on what we're seeing. When you look at our investor presentations, we draw a blue box around the acreage in West Williston that we believe is well delineated. Some of our acreage is outside the blue box and what we call extensional areas, which basically means that we need to drill some newer higher stage frac wells in the middle Bakken to give us a better feel for the results that we should expect in these areas. We have 2 extensional areas. The first which we call Target was right above Hebron in Montana and the other, which is referred to as Mondac, is right below Hebron and straddles the state line between Montana and North Dakota.
We have 1 Middle Bakken well planned at Target and 2 Middle Bakken wells planned in Mondak in our 2011 budget, which should help us further delineate this acreage. Together, Target and Mondak cover about 47 1,000 net acres. Since we're able to drive operations on our large contiguous block, we're working with a third party will build and own gathering lines and related infrastructure in the three areas that I just discussed, that being Indian Hills, Red Bank and Hebron. We should expect to see natural gas sales from these efforts in the Q3 of this year. Given the high BTU content of the gas in the basin, we expect to still clear north of Henry Hub pricing for our gas production.
We continue to explore gas gathering opportunities in East Nesson and oil gathering opportunities in West Williston, particularly in Red Bank. Lastly, infrastructure side, we are investing in saltwater disposal lines and disposal wells to reduce our LOE. If you truck water, it typically costs about 2 point $5.0 to $3 per barrel of water. But with this infrastructure, we can dispose of our water or produce water for less than $1 per barrel. Now, let's shift our focus over to East Nesen where we've been running 1 rig and will continue to run 1 rig throughout 2011.
We are maintaining our gross reserves average between 350,000 barrels of oil only or on an equivalent basis 400 to 675. Although this area is still in early stages of development, our Eastside wells within our core areas still look to be within our expected EUR range, closer to the high end of the range to the southern end of the block and the lower end of the range to the northern end of the block. The lower EUR range in East Nesson relative to West Williston is due to lower reservoir pressure as you head north in the East Nesson block as well as higher water saturations and more variability in water cuts. The acreage in Southern Burke County works well as we've discussed before. The Ernst well continues to perform well above the bottom end of our type curve range
and in
the second 30 days it produced an average of 3.90 BOEs per day, only down slightly from the 1st 30 days of 4.41 BOEs per day. That second 30 day rate puts the Ernst Wells performance well within the type curve band and somewhere in the 400,000 barrel range. Across all of these nets, we expect to drill 10 gross ounces.
Good morning. My name is Celeste, and I will be your conference operator today. At this time, I would like to welcome everyone to the 4th Quarter and Year End 20 10 Earnings Release and Operations Update for Oasis Petroleum. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, I would now like to turn today's call over to Mr.
Luz. Sir, you may begin your conference.
Thank you, Celeste. Good morning, everyone. This is Michael Luz, Senior Vice President, Finance. We're reporting our 4th quarter year ending December 31, 2010 results today, and we're glad to have you join our call. With me today from Oasis are Tommy News, President and Chief Officer Taylor Reid, Chief Operating Officer Roy Mace, Chief Accounting Officer and Richard Robock, Director of Investor Relations.
This conference call is being recorded and will be available for replay approximately 1 hour after its completion. The conference call replay and our earnings release are available on our website at www.oasaspetroleum.com. In addition, we have updated our investor presentation for the financial and operational results, which is on our website. Although we will not be speaking off the slides during this call, please feel free to refer to it for clarification. Please be advised that our following 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 anticipated. Those risks include, among others, matters that we have described in our earnings release as well as in our filings with the Securities and Exchange Commission, including our Form S-one and as amended. We disclaim any obligation to update these forward looking statements. Please note that our 2010 Form 10 ks will be filed tomorrow. During this conference call, we will also make references to adjusted EBITDA, which is a non GAAP financial measure.
Reconciliations of adjusted EBITDA to the bookable GAAP measures can be found in our earnings release or on our website. I'll turn the call over to Tommy.
Good morning, everyone, and thanks, Michael. First, I'd like to thank everyone for joining us this morning. I think it's fair to say that we have plenty to celebrate here at Oasis as it relates to the year 2010 as we ended the year with very impressive results, including a successful IPO. I'm very proud of the team that we've put together and what we've been able to accomplish. I'm also confident that they're ready to take on the challenges ahead in 20 11 as we continue to increase activity and focus on the drivers of value.
You've had much of our year end data now for over a month and as you know, we don't see much need in reading our press releases to you. So we'll try to focus this call on the high points for 20 10 and the outlook for 20 11. I will cover operations on production and had another 3 operated wells waiting on completion. And our 1 rig in East Nesen was drilling the Rude, which is in the southernmost portion of the block. Our Sanish Area wells are not operated, but as you all are familiar with, are very prolific.
Our production in the 4th quarter increased to 1900 BOEs per day, which is a 31% increase over the prior quarter. Across our 9 1,000 acres, we have a working interest here ranging in individual wells from less than 1% to as much as 15% and most of those wells operated by Whiting. At year end 2010, we had an inventory of 189 gross wells and 17 net wells in Sanish And Whiting announced in February of 2011 that they are increasing the number of 3 force wells per spacing unit from 2 to 3, which could potentially add another 86 gross wells to our inventory. Now that we've covered operations and well performance, I'd like to direct our discussion to a couple of more macro issues. Not that it's any surprise to anyone, but this has been a winter characterized by above average precipitation and some intense weather storms across the entire northern tier of the United States.
While we always plan for rough winters in the basin, we were not immune to the greater than expected slowdown that the weather caused this past year or this past winter, which is why we indicated in our press release that we are currently expecting to be at the low end of our production guidance for the 1st and second quarter of 20 11. The weather has affected our ability to get wells completed and inhibited our ability to move oil from existing producing wells. The good news is that we should be able to continue to grow our quarter over quarter production despite some of the operational disruption and we continue to expect to be within our previously announced annual production range of 11,000 to 12,500 BOEs per day. As a point of reference about the impact as of March 1st, we had 18 wells that were waiting on completion compared to 10 wells on November 30, 2010. As conditions improve, we will work down this backlog.
Another challenge that everyone has been discussing is pressure pumping services, not just in the Williston, but in all the resource plays. With the increase in rig count in the Williston to over 170 rigs, these services on the pressure pumping side have not increased as rapidly. Things even tighter. All of this is putting upward pressure on prices. We believe that we will be able to absorb an increase in completion costs within our existing CapEx budget, given that we included a bucket for contingencies in our development capital.
We had well costs as we exited 2010 at around $7,000,000 to $7,400,000 for a 28 stage job. But we think that well cost currently should be more around the $7,500,000 range, which is more in line with what our budget, including the contingency, would have implied. One other thing to remember is that our base case in the budget had WTI at $78 per barrel. And just last week, we put on a we set out at the beginning of 2010 to establish our drilling program in the Williston Basin in order to grow production and reserves. We definitely achieved that in what we set out to do as we grew from 2 rigs at the end of 2,009 to 6 rigs at the end of 2010.
We have another rig showing up in the Williston around the end of this month, which will give us 6 rigs in the West and 1 rig in the East. We grew production to 7,511 BOEs per day in the 4th quarter and ended the year with reserves of 39.8 millimeters millimeters millimeters millimeters millimeters millimeters BOEs. We also completed 2 strategic bolt on acquisitions in Montana that we're very excited about and we'll give you some more color on what we're seeing there in this area, which we call Hebron in a minute. When we started Oasis in 2,007, we had a clear focus on oil and we've been rewarded for this decision throughout 2010 and into 2011 as our oil weighted has accumulated over 300,000 net acres in the Williston Basin. And since we got an early start coupled with doing some opportunistic acquisitions in the 2,009 down cycle, our average acreage cost is very low and our acres are well positioned.
Having this large position in place allows us to direct a large portion of our CapEx to the drill bit. We drilled, completed and placed on production 26 operated wells in 2010. And as of March 1, we have 21 operated wells in the West and 12 operated wells in the East on production from our latest drilling program that started in late 2,009. We invested $243,800,000 or 70 percent of our CapEx in development throughout 2010. Since 40 5% of our production in the Q4 of 2010 and 70% of our CapEx for the year was associated with our West Williston project area, I will focus on the results there first.
As you all know, we have set type curves in the West Williston mentioned in our August call, our Angel well had been performing on or above the top end of the type curve range and is still performing around the upper end of the type curves. We call the area around the Angel Well Indian Hills. This area represents the deepest part of the basin and has comparatively high reservoir pressure and also a higher hydrocarbon core volume. We currently have 4 wells producing in this area, all of which have EURs towards the upper end of our type curve range. So we're very pleased with that.
We have about 23,000 acres in the block and budgeted about 20% of our 2011 drilling plan in Indian Hills. Our largest block of land is in an area we call Red Bank, where we have approximately 63,000 acres and currently have 14 wells in the area. This is our northern block in Williams County. We completed 12 of the 14 wells north and one well south off of the same pad and adjacent 1200 weight column for 1,000 barrels a day for the rest of the year at 95 by 117 when the swap rate was above $103 per barrel. While we do have some service cost creep with higher oil prices, we're trying to do some things to mitigate that, including hedging.
As we look to add rigs starting with our 7th rig in a few weeks, we'll have to make sure that we can match frac slots with the wells we're drilling. Fortunately, we have a number of interesting options that we are currently exploring as we look to bring on at least one more full time crew in the near term and potentially another in the next 12 to 18 months. Unfortunately, we're not in a position to give you more definitive information on that today, but we'll update as we can as it is a very important component of our execution plan, as you all know. I'll wrap up my comments I'll wrap up my comments with another broader discussion about the decisions that we've made based on some science work we've been doing across our operations. We are primarily completing our wells with or were with 28 stages through 2010.
And as we knew these wells were above our economic thresholds and well within our type curve bands, and we were very comfortable with the linear relationship of oil recovery per stage up to this level. We have added several 32 and 36 stage jobs to test the impact of additional stages on recoveries and results so far are very encouraging. With costs around $100,000 per stage and recoveries in the range of say 15,000 to 20,000 barrels of gross reserves per stage or 12,000 to 16,000 net. The incremental F and D cost should be in the $6 to $8 per barrel range, some of the most efficient capital that we can spend. Decided to go ahead and complete the majority of our remaining operated wells with 36 stages for the remainder of 2011 with a focus specifically on Indian Hills and the southern part of the East Nesham block.
When we think about acceleration, which capital that we raised in February. Now the next obvious question you'll have is the impact on production and CapEx. We're not in a position to share that with you today, but we'll keep you posted as we work through our plan. We'll pick up our 7th drilling rig around the end of this month and we'll be working on getting it operating safely and efficiently. We also expect to have a second dedicated frac crew, as I mentioned earlier, lined up in the near future and could see ourselves running 3 dedicated frac crews sometime in 2012.
So it's easy to see that Taylor and his team have been spending a lot of time securing services critical to our execution plan and they're doing a great job. Having these services in place would give us the flexibility when it comes to adding additional rigs, increasing the number of frac stages per well or doing other optimization work such as refracs. We like to approach decisions like these from one direction as you've heard us say so many times in the past. But we do know that at the current pace of development, we're very well positioned to hold our acreage position by production over the next couple of years. I will now turn it over to Michael to discuss a
few financial highlights. Thanks, Tommy. On the financial front, there's really nothing that you haven't already heard from us. We reported reserves and updated operational ranges for 20 10 in January and our actuals were right in line with what
we said they would be.
On the heels of the January operational update, we update, we raised $400,000,000 of debt, which would give us on a pro form a basis just over $530,000,000
of cash
and 6 $70,000,000 of overall liquidity as of December 31, 2010. We expect our current liquidity will fund all of 20 11 CapEx and well into if not completely through our 2012 capital program. For the full year 2010, we had realized prices of $69.60 per barrel and differentials of approximately 13%. Differentials gapped out to over 14% in the 4th quarter, primarily due to the Enbridge aggressive drilling program, we're putting in additional financial hedges like Tommy said and we continue to evaluate and add rail deals on gross operated volumes volumes in order to protect against some of the downside commodity risk. In turning rail, you may have seen the latest presentation on the North Dakota Pipeline Authority website, which has slides from the February 28th North Dakota's crude oil rail transportation infrastructure webcast.
It has some information on the plans and capacity for rail coming out of North Dakota. A couple of quick notes before we open the call for questions. LOE picked up from $6.33 per barrel in the 3rd quarter to $7.92 per BOE in the 4th quarter. This was really just making sure that we are fully accrued for operating expenses. We continue to see LOE decrease in 20.11 down into the $5 to $7 per BOE range.
G and A ended up in the range that we expected and Q4 was higher than Q3 primarily due to the fact that our full year bonus was accrued in December instead of being accrued across all four quarters the year. We talked about this on the November call and we've decided to accrue bonuses throughout the year if warranted from now on. All told, we had a successful 2010. We more than doubled production. We almost tripled reserves and adjusted EBITDA was up almost 5 times to $82,200,000 We have a strong balance sheet with plenty of cash to invest into our greater than 20 year drilling inventory, which will drive growth in shareholder value.
With that, we'll turn the call back over to Celeste to open the lines up for questions.
Real quickly on the 18 wells that are drilled and waiting on completion.
88 to drill blocks. If the wells are being drilled back to back, the rig can easily skid from 1 to the next. And as you've heard us talk about before, this setup also helps the completion process as we can pump 1 frac stage on one well while we set the plug and perforate on the other. Lastly, the way we have our pads configured, we can run gas, oil and water pipelines right through the pads. And as you look at our maps, we have quite a few straight lines running through this Red Bank area, meaning we have set up our drilling locations so that over the long run, we can run our operations just like a manufacturing process.
Given the well results to date, the operating efficiency that we have in this large contiguous block and the protection of our lease position, 42% of our drilling budget in 2011 will be in the Red Bank block. Wells in Red Bank are not quite as prolific as the wells in Indian Hills, but are clearly within our original expectations and look very good nonetheless. Red Vance is shallower than Indian Hills and therefore has a little less reservoir pressure and we estimate a slightly lower hydrocarbon pour volume. So the fact that they are lower in our type curve range makes a lot of sense to us. Now let's move over to the block in Richland and Roosevelt Counties in Montana in the area that we generally call Hebron and just adjacent to it, Missouri, where we picked up about 27,000 acres in the 4th quarter and now have a total of 57,000 net acres combined.
We have 3 operated wells that are producing that were drilled by the previous operator and completed in a manner similar to what we do but with less stages. Those wells are the Lutz Sweetman on the south central portion of the block, the Amazing Grace on the east side of the block along the state line and the Beulah Irene on the west side of the block about 10 to 12 miles from the Amazing Grace. While the Beulah Irene was drilled and set up by the previous operator, we actually at Oasis completed it after the acquisition. We now have 2 other operated wells, the Mary Wilson and the Wilson that we have drilled on the Montana side of our block and we're waiting on completion as of March 1. These wells are both set up as 28 stage completions and one of the wells, the Wilson will be completed in the Free Forks.
We are very pleased to have the Beulah Irene, our furthest West Middle Bakken completion, produced in line with the amazing Grace well, which as I mentioned is on the east side right on the state line. Based on early production data, we are very comfortable that the area between these two wells will similar results. And given that these wells look to be within our type curve ranges with 23 stages, we are very excited about the potential to be realized with 28 to 36 stage jobs across the Hebron block. We will basically run one operated rig in Hebron throughout 2011. We also have 2 wells waiting on completion just across the state line in North Dakota Dakota and one of those, the Moore is a Three Forks completion.
So we should have 2 good Three Forks 4th tests on our position here in the near future. These should be informative tests for us and we'll keep you posted as we get meaningful data over the next two quarters. We also expect to drill a Three Forks test.
You mentioned that weather is the primary component there. Has access to services been a challenge? And you talk about adding an additional frac crew. Will that alleviate that challenge? Or do you think about maybe even looking at vertical integration like some other folks have spoken about?
Dave, what I would tell you is that the build in the backlog is really a function of the weather that we experienced. And I mean, it's always difficult fracking wells in the winter, but this year was particularly brutal. So I think the build and the backlog was largely around the weather. Then with respect to additional crews or additional pumping services, we're looking at a lot of things. And as I mentioned, we've got a lot of interesting alternatives to consider.
But it looks like we'll have a dedicated crew here in the next couple of months. And once that comes on, we'll really be able to start working that inventory off, that backlog off and especially given that we'll be doing it as we go into some better weather than what we've experienced
But it's a
little bit higher than what we like. But it's a little bit higher than what we like, but again, primarily weather driven. That's
the first production kind of times look like? Are they in the past you've talked about just under 90 days or are we getting more efficient on that end as well?
Yes, hard to say because it's I think that's a good normalized run rate. Obviously, the backlog it's going to grow a bit.
Okay. That's helpful.
At least in the near term, Dave. I mean, ultimately, I think we'll ultimately normalize back to 90 until we get to the point where we're really in full blown pad and pattern drilling where we can start to really drive that down meaningfully.
Okay. That's helpful. And then one question just on reserves. When we look at the proved reserves, can you talk about the spending plan that matches up with that? Is that a plan that is essentially within discretionary cash flow outside of discretionary cash flow over the 5 year period?
Yes. I think Taylor has got that.
So you are talking about capital for our PEDs? Exactly. So there's total capital for all of our booked PEDs are just under $350,000,000 So when you look in gross well count, it's 100 and 24 net wells, 53. So when you look at cash flow, the 5 year period with that plan, it's still in line with our cash on the balance sheet plus our cash flow, yet plenty of capital executing on that plan, it's well below what we're going to spend.
So if you look at that just notionally without dragging you through CapEx every year, so that would be about $70,000,000 a year. And EBITDAX for last year was 82,000,000 dollars If you use our 4th quarter run rate, it'd be about 120,000,000. So, we're clearly covered.
Great. That clarification is very helpful. I'll let somebody else jump on guys.
Thanks.
Your next question comes from the line of Ron Neals with Johnson Rice.
Good morning, Ron.
A couple of questions. You did a good job of walking through your individual areas at both West Williston and East Nesson, is there as you look at your Montana acreage and the Hebron acquisition, that also being applied to the Montana acreage as well?
Yes, Ron. So it's in essence, it's about 14% of our CapEx. And as we talk about 1 rig programs typically will consume about $50,000,000 per year and we expect to run 1 rig over there. So I think our actual CapEx is around $60,000,000 So it's a little bit higher than that with some of the things that we're doing. But that's a good way to think about it.
We'll continue to at least for the foreseeable future through this year continue to run 1 rig and that is sufficient to help us protect our position there. As we've mentioned with the 4 100000 type curve range early days, but looks like the well the existing wells there are producing within that range with 23 stages. And so when you start thinking about adding incremental stages, even just getting up to what we normally do 28, then we think that that range is pretty solid.
And then that leads into the second question. You utilized a 28 stage process through most of last year. If you look across your different project areas, do you think it will be pretty universal that you can utilize 30 6 stage fracs in even the Montana in early days since you're really starting to really test the Three Forks, but a similar process in the Three Forks or will you also march up along that frac stage curve?
What I would say about that Ron is that I think that in the middle Bakken, I think we'll clearly be transitioning to 36. I mean even the Ernst well that we did over on the East side in East Nesson, remember was I think 25 plug and perf stages and 11 sleeves or something, may not be exactly disclosed. So I think you'll see us transition there on the middle Bakken. With respect to the Three Forks, we don't have enough history to be as confident about that linear relationship between stages and recoveries like we do in the Middle Bakken because we just have so much more data. So we just again, we need to approach it from one direction as we think about the Three Forks.
Okay, great. And then lastly, just on the infrastructure, infrastructure, you mentioned whether it's yourselves or third parties building out infrastructure. What's the timeline of that? I'm assuming you're talking about both clean and dirty water and gas lines being put in relative to your development plan?
Yes. Taylor, you want to take that? So the gas infrastructure on the west side, we'll have Indian Hills, Red Bank and Hebron should be hooked in and wells producing by Q3. The infrastructure for saltwater disposal, we've got ongoing work in Indian Hills, Hebron and over on the East side and all of that should be up and running by the Q4.
And is that one of the things that will then drive that LOE down as we dollars
to dollars to $3 a barrel. When we get our systems in place, you'll cut the cost under $1 a barrel, so it'll down LOE quite a bit.
Great. All right, guys. Let me let someone else jump in. Thank you.
Thanks, Ryan.
Your next question comes from the line of Oliver Dulin with Tudor, Pickering, Holt.
Good morning, guys. Just wondering, could you comment just some of your competitors have hedged production based on estimated production going forward. Just wondering how do you see that? Is that a possibility for you? And kind of what are the things you look at when you're looking at hedging?
I'll let Michael pick that one up.
Sure, Oliver. Right now, we've got 7,000 barrels a day hedged in 2011. We've got mainly collars and three way collars. And as you heard Tommy talk about, we're putting in more each day and just kind of layering them on. More recently, we've been focused on between $80 $95 floor levels, just given the run up in the oil price.
If you think about it from a couple of standpoints, if you look at it compared to Q4, we're basically for 2011 at our 4th quarter level. If you look at it compared to our expected range for this year, we're just north of 50%. 2012, we've got 5,500 barrels a day hedged right now and we've got about 2,000 barrels a day in 2013. We'll continue to layer on more given that we know that expected production will likely be much higher than those levels. Something
along the lines of can you comment on
the something along the lines of can you comment on the amount of Three Forks wells versus Bakken wells you plan to drill this year, either qualitatively or preferably quantitatively?
We've got 69 total gross operated of those Taylor 5 roughly 5
3, 4, 12 wells.
Great. Thank you. That's all I had.
Great. Thanks.
Your next question comes from the line of Derrick Whitefield with Canaccord.
Good morning, guys.
Good morning, Derrick.
High level question for you. And thinking about your current liquidity in development plans, I'm interested in your thoughts on accelerating development beyond the current program. And maybe more specifically outside of services, are there any other organizational objectives you're hoping to check off before pursuing a more aggressive development program?
What I would say is that as we talked about 1st phase for us is working through additional stages. We are looking at pressure pumping services as kind of being a driver to pace, as I alluded to earlier. But we've got to, as we've always talked about, we want to make sure that we've got enough pressure pumping services to support rigs that we bring on. So we don't want to drill a bunch of wells that we can't complete. So like a lot of things, we'll try to approach it from one direction.
Not inconceivable to think that with some of that, we have 2 full time crews up and running, that towards the end of the year we can pick up another rig and then see where it goes from there. Organizationally, we have grown from May, we were roughly 30 people pre IPO full time. Now it's a bit over 60. And so far, I mean, the guys spent a lot of time on it, as you can imagine, doubling headcount in 6 months. But I think within what's reasonable to expect, given the service infrastructure and timing that we can fill the slots that we need to accommodate that on the manpower side.
Got it. That makes sense. And then could you comment on the preliminary data you're receiving from drilling operations on the Wilson and Moore Three Forks wells? And then perhaps more specifically, is there anything you're seeing in the geology that encourages you to go after the Three Forks objective versus the Bakken?
So the Wilson and the Moore wells are consistent with what we saw in drilling the horizontals with the vertical penetrations in area. So we're just going to have to see how they perform when we test the wells. Three Forks relative to the Bakken Just don't have enough test on the West side, really across all of our acres position to tell you how the Threefour will perform relative to the Bakken yet. And so as we get to the end of this year, we've got 5 wells we've been talking about tested, we're going to have a much better indication of relative
performance.
Okay. It's very helpful. And then one final question. What are your latest thoughts on marketing arrangements given the recent spread between WTI and LLS?
There is clearly there's a disparity there. And I think like a lot of other guys in the basin, we're looking at options to be able to get our oil to different markets. There are some rail options to get to LLS St. James. And so we're looking at all those things.
Most of our oil right now is marketed through 3rd parties and we end up with an index either off of WTI or Clearbrook for the most part. So we don't yet have a lot of closure to LLS, but some we're looking at.
The other thing to keep in mind is that that differential, WTI to LLS differential has run up pretty good in the last few months. But just given the timing of how it's run up, it's pretty volatile. So what you don't want to do is run out and spend a whole lot of capital to solve something that's a short term blip if that's the way it turns out.
That's a
fair point. Just wanted to get your color and thoughts on that. That's all for me guys. Thanks.
Perfect. Thanks.
Your next question comes from the line of Steve Berman with Pritchard Capital.
Good morning. I was wondering if you could touch on any thoughts you might have on density drilling with Brigham talking for Bakken and 4, 3 forks per 12.80. What's your thoughts on that as far as Oasis and just in general goes?
Yes, Steve, what I would say is, it's still early days, but it certainly looks like that it's a minimum of 3 and likely 4. Fortunately, we'll have some good information here over the next 12 months to verify before with 3 wells, you get what we estimate based on our subsurface mapping 12% to 15% of original oil in place. So you have to think that
more is going to be required to
get that ultimate recovery up. Three Forks, so as we talked about, we saw Brigham I'm sorry, Whiting say that they're going from 2 to 3. So, but we just we've got a fair amount of data though within Sanish. So, it looks like it's moving in that direction as well, but it's just too early to kind of throw down a number and say it's absolutely that.
Okay. And if you touch on this, I apologize, but any plans on further testing of the testing the Burke County acreage where you drilled the REBNY well?
Yes. I don't think that we've got anything in this year's capital program with the revenue. The guys are still looking at some of the options for reverse engineering on that as we've talked about before. We probably do have a little bit of lease exposure there, but in the overall scheme of things, it's not significant to our inventory. As you may know that our last pass of inventory, we excluded that out and basically now we're calling it more of a contingent area.
Got it. All right. That's it for me. Thanks guys.
Thanks, Steve.
Your next question comes from the line of Bob Morris with Citigroup.
Good morning. Good morning, Bob. When you talked about going from 28 to 36 stage fracs, are you spacing those tighter or are you now drilling laterals that are longer than 10 1,000 foot?
No, it's tighter spacing. The laterals are still 10,000.
Okay. And did you say that all your Bakken wells this year would be 30 6 stage?
Yes. The module for sure in Indian Hills and the southern part of East Nesson, some of the wells are already drilled and already done at 28 stages. So there's only so much we can do obviously. But going forward, the majority of them will be 36 stages. Is that fair to say?
Yes, yes.
In those two areas and then we're continuing to test 36 stages and with some select wells in Red Bank and we'll drill additional wells there with 36 stages this year. Early results are encouraging, so you may see us move that area to all 36 stages a little later in the year.
Okay. So for those two areas, you're fairly confident at this point that the range on the type curve, you can move those up by 150,000 barrels with the 30,060?
Yes. On a net basis, I think we've been calling it roughly $100,000 to $120,000 Okay.
And then when you said your budget reflected $7,500,000 per well for that of correspondent to 24 stage frac, with most of these wells, a lot of these wells being now 36 stage, then we need to incorporate a little bit higher well cost on average in the budget than that $7,500,000 Is that correct?
Yes. The $7,000,000 when we our typical design has been 7.2 to 7.4, 28 stages. I think you said 23 or 24. 28 stages, 65% ceramic, 35% sand. Keep in mind that as others have talked about and we've talked about for a long time, we're that varies a bit by geographic pod.
And now that we've got the wells within the type curve ranges, we play with a lot of things,
including concentrations per stage and
compositions per stage in some compositions per stage in some places we use all white sand. But as we came into the end of last year, 1st of this year, end of that last year really, it was what we saw in actuals was more in the 7% to 7.4%. We're thinking with some of the cost creep on a 28 were more in the 7.5 range, maybe a little bit higher. But then as we start doing these others with 36 stages and 100 1,000 stage, then that will start to bump the number up. And so we'll have to I mean, we're working through all that right now to try to get a feel for impact on our CapEx spend.
And it's easy to just apply the number to the well count, but you got to consider timing and timing of stimulation services once you start doing 36 stages and what that means to how much does that net down to on a net basis? 47.
47. Does that net down to on a net basis?
47. 47.
Great.
And then there's 6 47 and 6. So, there's 6 net non op wells against the total program to 53, the 69 goes to 47 on strict the operator side.
Okay, great. Thank you very much.
Hi, Bob.
Your next question comes from the line of Irene Haas with Wunderlich Securities.
Hello, everybody. I have a question on 3 for Spanish. Can you hear me? Yes. Okay.
Just excited that you guys are starting to drill it and just want to get a sense of spatially how these 5 wells are spread out and how you feel about the reservoir configuration within the Three Forks? Should we expect something probably a little more variable versus what we used to in the middle Bakken? And so just a little more color on this really kind of exciting set of a pipeline?
Yes. At a macro level, what I would say is based on what we've seen at least on the west side with some of the Brigham wells, the data so far would indicate that the Three Forks would be consistent within those type curve bands. As you start to move below that and we'll have some more data. It's kind of with the Brigham wells, there's a fair amount of data kind of on the east side of our western position. Obviously, with these 2 new wells that straddle the state line right around the Hebron, we'll have some really good data there.
We had that 1 Continental Overt well that looks good over on the state lineup in the Red Bank block. So, we just need some more data points. Taylor, you want to add?
So we've got actually one well in Indian Hills that's drilled but not yet completed. It's a 3 corks test. There is a test by another operator that has recently been released. It's only a month production, but it looks very encouraging.
And it's right off the southeast corner of our Indian Hills block.
Does it get better as you approach northward towards the sort of basis edge? Does it get better in terms of velocity at least?
It's really It's really area dependent. We've done the same thing in the 3 ports that we've done in the Bakken, which is try to map hydrocarbon pour volume ultimately a little in place. So water saturation is important as well as thickness and reservoir quality. So there is some variability. To your question about where will we drill, we've got the 2 in the Hebron area.
We'll drill 1 in Red Bank, 2 in Indian Hills and one in the southern part of the East Knutsen this year. Those are the 5 wells.
Got you. How far would your footprint be from these 5 wells? How big an area are you blanking?
I don't understand how big is the area.
If you look at if you just go from the state line, where the 2 wells are that straddle the state line over to where our well is in Indian Hill, that's roughly 3.5 or 4 townships.
Okay.
Your next question comes from the line of Marty with Northland Capital.
What are you seeing for opportunities for potentially acreage acquisitions for 20 11 11? And what kind of quality is the acreage that you're seeing? And what type of pricing are you seeing for
just for routine land acquisition about $20,000,000 We've been able to add acres in and around our blocks depending on the geographic pod for anywhere from 4 to $400 to $800 an acre without brokerage costs. And it's mostly relatively small parcels, but we have been able to supplement our blocks in that range. Now bigger blocks typically will cost a bit more. You saw that with the Hebron deals that we did at the end of last year.
Are you seeing many potential acquisitions for bigger blocks of things that you would be interested
in? There's continue to be things that pop up. One of the things that we have to be very careful of is going out and spending a significant amount of dollars on blocks at very high per acre costs when we've got already 300,000 acres at an average cost in of $3 to $3.50 an acre and plenty of inventory to keep us busy.
Okay. And then also for your G and A outlook for the year, what is your current guidance for G and A excluding stock based comp considering that it sounds like you'll be accruing bonus throughout the year?
Yes. Michael, you want to Yes.
Our guidance is $6 to $7.50 per BOE. That does include stock based comp to that.
That does include stock based comp?
It does. That's all in.
Yes. Keith and Mike, we may want to just touch on that. I mean, there's a couple of different components of clarification 10 that can cause some
So we have a line item that is called stock based comp and we go through it in detail both in our S-one at the IPO as well as in the press release you've seen. Stock based comp under that is actually a bit of an unusual item where
wells in 2010. As of March 1, we had 12 operated wells on production and had another 3 operated wells waiting on completion. And our 1 rig in East Nesson was drilling the Rude, which is in the southernmost portion of the block. Our Sanish Area wells are non operated, but as you all are familiar with, are very prolific. Our production in the 4th quarter increased to 1900 BOEs per day, which is a 31% increase over the prior quarter.
Across our 9,000 acres, we have a working interest here ranging in individual wells from less than 1% to as much as 15% and most of those wells are operated by Whiting. At year end 20 we had an inventory of 189 gross wells and 17 net wells in Sanish and Whiting announced in February of gross wells to our inventory. Now that we've covered operations and well performance, I'd like to direct our discussion to a couple of more macro issues. Not that it's any surprise to anyone, but this has been a winner characterized by above precipitation and some intense weather storms across the entire northern tier of the United States. While we always plan for rough winters in the basin, we were not immune to the greater than expected slowdown that the weather caused this past year or this past winter, which is why we indicated in our press release that we are currently expecting to be at the low end of our production guidance for the 1st and second quarter of 2011.
The weather has affected our ability to get wells inhibited our ability to move oil from existing producing wells. The good news is that we should be able to continue to grow our quarter over quarter production despite some of the operational disruption and we continue to expect to be within our previously announced annual as of March 1, we had 18 wells that were waiting on completion compared to 10 wells on November 30, 2010. As conditions improve, we will work down this backlog. Another challenge that everyone has been discussing is pressure pumping services, not just in the Williston, but in all the resource plays. With the increase in rig count in the Williston to over 170 rigs, these services on the pressure pumping side have not increased as rapidly.
With few folks completing many wells between December January due to the weather, that makes things even tighter. All of this is putting upward pressure on prices. We believe that we will be able to absorb an increase in completion costs within our existing CapEx budget given that we included a bucket for contingencies in our development capital. We had well costs as we exited 2010 at around $7,000,000 to 7,400,000 dollars for a 28 stage job. But we think that well cost currently should be more around the $7,500,000 range, which is more in line with what our budget including the contingency would have implied.
One other thing to remember is that our base case in the budget had WTI at $78 per barrel. And just last week, we put on
to employees. So, it hits our books, but it's non cash, non dilutive to shareholders. It's not the same as of normal restricted stock grants that might be given by the company. So, there is a component of that that is actually in our G and A. And so, when we're guiding the G and A numbers, we're talking about all in with that normal stock based comp that a a company
would pay. Okay. All right. Thank you.
Your next question comes from the line of Marshall Carver with Capital
results of other operators. And I know that you're spending most of your drilling the whole acreage. But do you have any plans for any down spacing tests in the Bakken this year for Oasis operated wells?
Tyler, you can go ahead. Yes. We've got we don't have any plans to do any tight spacing tests this year. The focus is really on holding our acres 1 well per spacing unit. We will drill 2 wells in fairly close proximity and plan to frac both of those wells at the same time and be microseismic.
So we are trying to get some of that data. It's not quite as tight as you might see for example 4 wells per spacing it will close enough we'll get some of that data.
When do you plan on drilling those 2 wells?
Yes. Those will be completed later this year. One of them is currently drilled.
Okay. So that would be a second half twenty eleven event?
Yes.
Okay. That's it for me. Most of my other questions were answered. Thank you.
Great. Thanks, Marty.
Your next question comes from the line of Peter Mahan with Dougherty and Company.
Yes. Good morning, guys. Most of my questions have been answered as well. But one thing I didn't want to ask about is how many of your acreage is at risk for exploration in 2011, 2012? And where would that acreage be?
Yes. So we'll get some we'll have a detailed table that will be in our 10 ks, but for 2011, it's about 54,000 net acres is at risk. Anyway, I mean just start with that. 2012, 24,000 net acres, we think in both cases, we can preserve all of what we want to with our drilling program. Most of what will be exposed is more in some of the higher cut areas over on the East Nesen side that wouldn't be in our inventory anyway.
As we think about conversion to HBP, we've got about 90,000 acres HBP currently. And with our drilling program over the next 2 years, we HBP about 60,000 acres a year. So as you get into the end of 2012, you're going to be somewhere in the 220,000 range. So we feel like we're in real good shape.
Perfect. Great. Thanks a lot for the color.
You bet. Thank you.
Your next question
Wilson and the Wilson wells at Hebron waiting on completion. Can you provide any timing on the completion date for those 2 wells and those are being completed with 28 stages, correct?
Correct. I think the Mary Wilson is currently fracking.
Correct.
I don't know what the timing is of the Wilson yet, but the Mary Wilson is the middle Bakken well.
Right.
In the second quarter, we don't have an exact date yet.
Okay, very good. And then the investments in the saltwater disposal line and system, just roughly what is the capital investment for that?
Total capital for infrastructure for the year is $20,000,000 So there is mostly the SWD gathering systems and SWD wells, but there is some additional capital for electrification and things like that. I don't have the exact breakout, but most of it is SWD.
Got And then one more if I could. Just generally, can you give us a sense of the rate to frac crew ratio in the basin in the Williston Basin today and how it's trending or how do you expect it to trend over the balance of 20 11? Is it as high as
don't know that
I've got an exact ratio, but it's clearly undersupplied right now. And based on the rig count, the way we've been looking at it is it's for all operators backlog of completions. If you stay flat on rigs, from what we're hearing is going to come into the basin, the basin might be in in balance by the end of the year. If rigs continue to pick up and you get more increases, it's going to take longer. And then as you're adding, like we've been talking about more intensity of frac stages that pushes it out in time.
Yes, indeed. And then one more lastly here. I'm sure you see your share of property packages and I'm sure you've got a few on your desk today. Can you share with us any texture just generally on those property packages? Where are they being sourced from?
Are they more from private companies versus public companies? And if you were to add up the acreage on those same property packages that are again sitting on your desk today, what would they total?
Well, what I would say is that most of the things that we're seeing are more privately generated than public. I mean, there are some public things where people are doing cleanup or optimization work. You've seen those recently. If you were to add up everything that's floating around in the market today from an acreage basis, I don't even know if I could make a good wild guess.
It's 100 of 1000 acres.
Probably a couple 100000 plus or minus.
Got it. Thank you. All the best. Thanks.
You bet.
Your next question comes from the line of Teitra Sundaram with Cardinal Capital.
Thank Congratulations. Great quarter. Couple of things. You talked about the delta the current CapEx budget can saw the EUR 7,500,000 well cost. If you have decided to do the additional stages, about EUR 100,000 more per stage, So that would be an additional 800,000.
So I just wanted to get clear that piece is not currently in the CapEx estimate and you all are trying to get your arms around what that additionally be, correct?
Yes. So if you were to take just call it for fun, let's take 800 $1,000 and we've got 47 net wells, then that's 38 $1,000,000 roughly. Okay? And we already had 16 wells, which would, let's for fun, let's call it 8 or 9 in the budget. So plus you got to factor in timing.
So I mean, I'm doing this off the top of my head, which is why we're going to come up with a plan and we're going to tell you. But I'd say that it's probably 25 ish, maybe a little bit lower, dollars 20,000,000 Taylor?
Yes. That's was kind of great. Yes.
Probably closer to $15,000,000 when you look at working interest in wells and not all of them
will be $20,000,000 not all of the wells will be $26,000,000 Correct.
I don't have any to get down. So we think it's probably an incremental $15,000,000 at most by the end of the year. We just need to continue to work on it.
Yes. Can you help me understand how much of those 53 wells and apologize if you all have discussed this in the past, how many of those 53 wells that are in the CapEx budget are in the Indian Hills and the Red Bank, I think you said, area? So, it seem to be the most prolific.
Yes. We've got in So in Indian Hills, there's 17 wells? Gross. Gross, yes.
Hold on. So you've got net numbers and he's going to give you a gross and then maybe I'll hit you to net it down for me. Yes. I mean as a general rule, you use about 65%, but
Got it.
So 17 gross wells, about 12 net wells in Indian Hills. And the other area you're asking about was Red Bank.
I think it's the Red Bank, right?
Yes, Red Bank, there's 29 gross wells and that is about 21 wells net.
Great. Now so just philosophically, it is not possible to go back and increase the stages on already completed well? Or is that another opportunity?
Short answer is that as a general rule, what I would say is no.
Okay.
We did actually a couple of years ago go into a well where slow packers were already set, but the well had not been fracked and pulled the liner and set it up a different way. But mechanically that's challenging with our guys were able to get it done, which I was actually a bit surprised. But it's really not practical.
Okay. And my final question is just on talking about the pressure pumping services versus the pace at which you'd like to go, assuming you're able to get that additional 1, 2 crews as we go into 2012 dedicated crews. Is there anything in your control from the point of view of pumping services that would enable you to up the pace? Or is it just that you have the 2 additional crews, but you're still Saaved because services just keep up. So you never really get the pace that you might be looking for.
I guess what I would say is that as we think about it with the next crew in the next couple of months and then potentially another one sometime in 2012. I think that pace is sufficient for us. And so that is again, we try to we try not to bounce around with respect to equipment. So we try to approach it from one direction. And so as we can line up these pressure pumping services, then we'll look to add rigs.
I see. Okay. And finally, 18 wells waiting for completion versus 10 a year ago, there was some discussion earlier about if weather had not been an issue. What would I'm trying to understand how much of those 18 wells reflects weather versus the issue of getting the services to complete the well?
Yes. That was actually 10 wells at the end of November versus the 18 now. And as I mentioned, our I would expect a typical run rate on backlog on wells to be somewhere in that with current rig counts to be somewhere in the 8% to 10% range. Emotionally, I think you can think about the weather component of the 2018 being roughly 8.
Got it. Okay. Okay. So the services are not an outsized issue other than just a a normal part of the operating challenges. Thank you so much.
Okay. Thank you.
And you have no further questions. Great.
Well, thanks for your participation in our year end call. We'll be filing our 10 ks, our first 10 ks as a public company, in fact, tomorrow. And I'm proud of what all the Oh's team has been able to do in terms of delivering results that we'll see in that 10 ks that will come out tomorrow. We're pleased with our solid shareholder base and are enjoying meeting new folks at conferences and industry events. We'll be at a number of energy conferences in the next couple of weeks months and look forward to catching up with many of you along the way.
Thanks again. We had color for 1,000 barrels a day for the rest of the year at 95 by 1.17 when the swap rate was above $103 per barrel. While we do have some service cost creep with higher oil prices, oil prices, we're trying to do some things to mitigate that, including hedging. As we look to add rigs starting with our 7th rig in a few weeks, we'll have to make sure that we can match frac slots with the wells we're drilling. Fortunately, we have a number of interesting options that we are currently exploring as we look to bring on at least one more full time crew in the near term and potentially another in the next 12 to 18 months.
Unfortunately, we're not in a position to give you more definitive information on that today, but we'll update as we can as it is a very important component of our execution plan as you all know. I'll wrap up my comments with another broader discussion about the decisions that made based on some science work we've been doing across our operations. We are primarily completing our wells with or were with 28 stages through 2010. And as we knew these wells were above our economic thresholds and well within our type curve bands and we were very comfortable with the linear relationship of oil recovery per stage up to this level. We have added several 32 the impact of additional stages on recoveries and results so far are very encouraging.
With costs around $100,000 per stage and recoveries in the range of say 15,000 to 20,000 barrels of gross reserves per stage or 12,000 to 16,000 net. The incremental F and D cost should be in the $6 to $8 per barrel range, some of the most efficient capital that we can spend. Are deciding to go ahead and complete the majority of our remaining operated wells with 36 stages for the remainder of 2011 with a focus specifically on Indian Hills and the southern part of the East Nesham block. When we think about acceleration, which plenty of the folks have been asking us about, this really is the most efficient acceleration that we can do with the additional you today, but we'll keep you posted as we work through our plan. We'll pick up our 7th drilling rig around the end of this month and we'll be working on it operating safely and efficiently.
We also expect to have a second dedicated frac crew, as I mentioned earlier, lined up in the near future and could see ourselves running 3 dedicated frac crews sometime in 2012. So it's easy to see that Taylor and his team have been spending a lot of time securing services critical to our execution plan and they're doing a great job. Having these services in place would give us the flexibility when it comes to adding additional rigs, increasing the number of frac stages per well or doing other optimization work such as refracs. We like to approach decisions like these from one direction as you've heard us say so many times in the past, but we do know that at the current pace of development, we're very well positioned to hold our acreage position by production over the next couple years. I will now turn
it over to Michael to discuss a few financial highlights. Thanks, Tommy. On the financial front, there is really nothing that you haven't already heard from us. We reported reserves and updated operational ranges for 20 10 in January and our actuals were right in line
with what we said they
would be. On the heels of the January operational update, we raised $400,000,000 of debt, which would give us on a pro form a basis just over $530,000,000 of cash and $670,000,000 of overall liquidity as December 31, 2010. We expect our current liquidity will fund all of 20 11 CapEx and well into if not completely through our 2012 capital program. For the full year 2010, we had realized prices of $69.60 per barrel and differentials of approximately 13%. Differentials gapped out to over 14% in the 4th quarter, primarily due to the Enbridge 6B line and its impact to October differentials.
We believe differentials in 2011 will be on average in the 12% to 15% range. Given the current price environment in our aggressive drilling program, we're putting in additional financial hedge like Tommy said and we continue to evaluate and add rail deals on gross operated volumes in order to protect against Pipeline Authority website, which is slides from the February 28 North Dakota's crude oil rail transportation webcast. It has some information on the plans and capacity for rail coming out of North Dakota. A couple of quick notes before we open the call for questions. LOE picked up from $6.33 per barrel in the Q3 to $7.92 per BOE in the Q4.
This was really just making sure that we are fully accrued for operating expenses. We continue to see LOE decrease in 20.11 down into the $5 to $7 per BOE range. G and A ended up in the range that we expected and Q4 was higher than Q3 primarily due to the fact that our full year bonus was accrued in December instead of being accrued across all four quarters of the year. We talked about this on the November call and we've decided to accrue bonuses throughout the year if warranted from now on. All told, we had a successful 2010.
We more than doubled production. We almost tripled reserves and adjusted EBITDA was up almost 5x to $82,200,000 We have a strong balance sheet with plenty of cash to invest into our greater than 20 year drilling inventory, which will drive growth in shareholder value. With that, we'll turn the call back over to Celeste to open the lines up for questions.
Your first question comes from the line of Dave Kistler with Simmons and Company.
Guys. Good morning, Dave.
Real quickly on the 18 wells that are drilled and waiting on completion, you challenge? And you talk about adding an additional frac crew. Will that alleviate that challenge? Or do you think about maybe even looking at vertical integration like some other folks have spoken about?
Dave, what I would tell you is that the build in the backlog is really a function of the weather that we experienced. And I mean it's always difficult, fracking wells in the winter, but this year was particularly brutal. So I think the build in the backlog was largely around the weather. And then with respect to additional crews or additional pumping services, we're looking interesting alternatives to consider.
But it
looks like we'll have another dedicated crew here in the next couple of months. And once that comes on, we'll really be able to start working that inventory off, that backlog off and especially given that we'll be doing it as we go into some better weather than what we've experienced to 10 wells. But it's a little bit higher than the to 10 wells. But it's a little bit higher than what we like. But again, primarily weather driven.
That's helpful. Just maybe for a clarification too, if the weather hadn't been an issue, what did spud to 1st production kind of times look like? Are they in the past you've talked about just under 90 days or are we getting more efficient on that end as well?
Yes, hard to say because it's I think that's a good normalized run rate. Obviously, with the backlog, it's going to grow
a bit. Okay.
That's helpful.
At least in the near term, Dave. I mean, ultimately, I think we'll ultimately normalize back to 90 until we get to the point where we're really in full blown pad and pattern drilling where we can start to really drive that down meaningfully.
Okay. That's helpful. And then one question just on reserves. When we look at the proved reserves, can you talk about the spending plan that matches up with that? Is that a plan that is essentially within discretionary cash flow outside of discretionary cash flow over the 5 year period?
Yes. Taylor's I think Taylor's got that.
So you're talking about capital for our PEDs? Exactly. So there's total capital for all of our booked PEDs are just under 350 $1,000,000 So when you look in gross well count, it's 124 net wells, 50 3. So when you look at cash flow, the 5 year period with that plan, it's in line with our cash on the balance sheet plus our cash flow, yet plenty of capital to execute on that plan. It's well below what we're going to spend.
So if you look at that just notionally without dragging you through CapEx every year, so that'd be about $70,000,000 a year. And EBITDAX for last year was $82,000,000 If you use our 4th quarter run rate, it'd be about 100 and 20. So, we're clearly covered.
Great. That clarification is very helpful. I'll let somebody else jump on
guys. Thanks.
Your next question comes from the line of Ron Neals with Johnson Rice.
Good morning, Ron.
A couple of questions. You did a good job of walking through your individual areas at both West Willis and East Nesson. Is there as you look at your Montana acreage and the Hebron acquisition, what type of activity levels do you see in that area? And then the 400000 to 700 000 barrels that you've used for West Williston, is that also being applied to the Montana acreage as well?
Yes, Ron. So it's in essence, it's about 14% of our CapEx. And as we talk about one rig programs typically will consume about $50,000,000 per year and we expect to run 1 rig over there. So I think our actual CapEx is around $60,000,000 So it's a little bit higher than that with some of the things that we're doing. But that's a good way to think about it.
We'll continue to at least for the foreseeable future through this year continue to run one rig and that is sufficient to help us protect our position there. As we've mentioned with the 400 000 type curve range early days, but looks like the well the existing wells there are within that range with 23 stages. And so when you start thinking about adding incremental stages even just getting up to what we normally do 28, then we think that that range is pretty solid.
And then that leads into the second question. You experimented or you utilized a 28 stage process through most of last year. If you look across your different project areas, do you think it will be pretty universal that you can utilize 36 stage fracs in even the Montana in early days since you're really starting to really test the Three Forks, but a similar process in Three Forks or will you also march up along that frac stage curve?
What I would say about that Ron is that I think that in the middle Bakken, I think we'll clearly be transitioning to 36. I mean even the Ernst well that we did over on the East side in East Nesson, remember it was I think 20 5 plug and perf stages and 11 sleeves or something, may not be exactly disclosed. So I think you'll see us transition there on the middle Bakken. With respect to the Three Forks, we don't have enough history to be as confident about that linear relationship between stages and recoveries like we do in the Middle Bakken because we just have so much more data. So we just again, we need to approach it from one direction as we think about the Three Forks.
Okay, great. And then lastly, just on the infrastructure, you mentioned whether it's yourselves or third parties building out infrastructure. What's the timeline of that? And I'm assuming you're talking about both clean and dirty water and gas lines being put in relative to your development plan?
Yes. Taylor, you want to take that? So the gas infrastructure on the west side, so we'll have Indian Hills, Red Bank and Hebron should be hooked in and wells producing by Q3. The infrastructure for saltwater disposal, we've got ongoing projects in Red Bank with 2 wells currently operating. And then we're doing additional work in Indian Hills, Hebron and over on the East side and all of that should be up and running by the Q4.
And is that one of the things that will then drive that LOE down as we move through the course of the year?
Correct. As Tom said, the haul water is about $2.50 to $3 a barrel. When get our systems in place, you'll cut the cost under $1 a barrel, so it'll drive down LOE quite a bit.
Great. All right, guys. Let me let someone else jump in. Thank you.
Thanks, Ryan.
Your next question comes from the line of Oliver Dulin with Tudor, Pickering, Holt.
Good morning, guys. Just wondering, could you comment just some of your competitors have hedged production based on estimated production going forward. Just wondering how do you see that? Is that a possibility for you? And kind of what are the things you look at when you're looking at hedging?
I'll let Michael pick that one up.
Sure, Oliver. Right now, we've got 7,000 barrels a day hedged in 2011. We've got mainly collars and three way collars. And as you heard Tommy talk about, we're putting in more
each day and just
kind of layering them on. More recently, we've been focused on between $80 $95 floor levels, just given the run up in the oil price. If you think about it from a couple of standpoints, if you look at it compared to 4th quarter, we're basically, for 2011 at our 4th quarter level. If you look at it compared to our expected range for this year, we're just north of 50%. 2012, we've got 5,005 100 barrels a day hedged right now and we've got about 2,000 barrels a day in 2013.
We'll continue to just continue to layer that in over time.
Okay, great. Thanks. And then just my last question would be something along the lines of can you comment on the amount of Three Forks wells versus Bakken wells you plan to drill this year, either qualitatively or preferably quantitatively?
We've got 69 total gross operated of those Taylor 5 roughly 5, 3, 4, 4 wells.
Your next question comes from the line of Derrick Whitefield with Canaccord.
Good morning, guys.
Good morning, Derrick.
High level question for you. And thinking about your current liquidity and development plans, I'm interested in your thoughts on accelerating development beyond the current program. And maybe more specifically outside of services, are there any other organizational objectives you're hoping to check off before pursuing a more aggressive development
program?
What I would say is that as we talked about 1st phase for us is working through additional stages. We are looking at pressure pumping services as kind of being a driver to pace, as I alluded to earlier. And but we've got to as we've always talked about, I mean, we want to make sure that we've got enough pressure pumping services to support rigs that we bring on. So we don't want to drill a bunch of wells that we can't complete. So like a lot of things, we'll try to approach it from one direction.
Not inconceivable to think that with some of that, we have 2 full time crews up and running that towards the end of the year we could pick up another rig and then see where it goes from there. Organizationally, we have grown from May, we were roughly 30 people pre IPO full time. Now it's been over 60. And so far, the guys spent a lot of time on it, as you can imagine, doubling the headcount in 6 months. But I think within what's reasonable to expect given the service infrastructure and timing that we can fill the slots that we need to accommodate that on the manpower side.
Got it. That makes sense. And then could you comment on the preliminary data you're receiving from drilling operations on the Wilson and Moore Three Forks wells? And then perhaps more specifically, is there anything you're seeing in the geology that encourages you to go after the Three Forks objective versus the Bakken?
So, the Wilson and the Moore wells are consistent with what we saw in drilling the horizontals with the vertical penetrations in the area. So, we're just going to have to see how they perform when we test the wells. Three Forks relative to the Bakken just don't have enough test on the West side, really across all of our acreage position to tell you how the Threefour will perform relative to the Bakken yet. And so as we get to the end of this year, we've got 5 wells we've been talking about tested, we're going to have a much better indication of relative performance.
Okay. Very helpful. And then one final question. What are your latest thoughts on marketing arrangements given the recent spread between WTI and LLS?
Clearly, there's a disparity there and I think like a lot of other guys in the basin, we're looking at options to be able to get our oil to different markets. There are some rail options to get to LLS St. James. And so we're looking at all of those things. Most of our oil right now is marketed through 3rd parties and we end up with being indexed either off of WTI or Clearbrook for the most part.
So we don't yet have a lot of closure to LLS, but something we're looking at.
The other thing to keep in mind is that that differential, WTI to LLS differential has run up pretty good in the last few months. But I mean just given the timing of how it's run up, it's pretty volatile. So what you don't want to do is run out and spend a whole lot of capital to solve something that's a short term blip, if that's the way it turns out.
That's a fair point. Just wanted to get your color and thoughts on that. That's all for me guys. Thanks.
Perfect. Thanks.
Your next question comes from the line of Steve Vernon with
wondering if you could touch on any thoughts you might have on density drilling with Brigham talking for Bakken and 4, 3 forks per 12.80. What's your thoughts on that as far as Oasis and just in general does?
Yes. Steve, what I would say is, it's still early days, but it certainly looks like that it's a minimum of 3 and likely 4. Fortunately, we'll have some good information here over the next 12 months to verify that. But just notionally as you think about it as we've talked about before with 3 wells you get what we estimate based on our subsurface mapping 12% to 15% of original oil in place. So you have to think that
more is going to be required to
get that ultimate recovery up. Three Forks, so we just as we talked about, we saw Brigham I'm sorry, Whiting say that they're going from 2 to 3. So but we just we've got a fair amount of data though within Sanish. So, it looks like it's moving in that direction as well, but it's just too early to kind of throw down a number and say it's absolutely that.
Okay. And if you on this, I apologize, but any plans on further testing those Burke County acreage where you drilled the Red Knee
well? Yes. I don't think that we've got anything in this year's capital program with the revenue. The guys are still looking at some of the options for reverse engineering on that as we've talked about before. We do have a little bit of lease exposure there, but in the overall scheme of things, it's not significant to our inventory.
As you may know that our last pass of inventory, we excluded that out and basically now we're calling it more of a contingent area.
Got it. All right. That's it for me. Thanks guys.
Great. Thanks, Steve.
Your next question comes from the line of Bob Morris with Citigroup.
Good morning. Good morning Bob. When you talked about going from 28 to 30 6 stage fracs, are you spacing those tighter or are you now drilling laterals that are longer than 10,000 foot?
No, it's tighter spacing.
The laterals are still 10,000. Okay. And did you say that
all your Bakken Yes. The
module for sure in Indian
Hill, Yes. The Majul for sure in Indian Hills and the southern part of East Nesen, some of the wells are already drilled and already done at 28 stages. So there's only so much we can do obviously. But going forward, the majority of them will be 36 stages. Is that fair to say?
Yes, yes, in
those two areas. And then we're continuing to test 36 stages and with some select wells in Red Bank and we'll drill additional wells there with 36 stages this year. Early results are encouraging, so you may see us move in that area at all 36 stages a little later in the year.
Okay. So for those two areas, you're fairly confident at
this point that the range on the type curve, you can
move those up by
60?
Yes. On a net basis, I think we've been calling it roughly 100,000 to 120,000. Okay.
And then when you said your budget reflected $7,500,000 per well for that of correspondent to 24 stage frac, with most of these wells, a lot of these wells being now 36 stage, then we need to incorporate a little bit higher well cost on average in the budget than that $7,500,000 is that correct?
Yes. The $7,000,000 when we our typical design has been 7 point 2 to 7.4, 28 stages. I think you said 23 or 24, but it's 28 stages, stages, 65 percent ceramic, 35 sand. Keep in mind that as others have talked about and we've talked about for a long time, where that varies a bit by geographic pod. And now that we've got the wells within the type curve ranges, we play with a lot of things, including concentrations per stage and compositions compositions per stage in some places we use all white sand.
But as we came into the end of last year versus this year, end of that last year really, it was what we saw in actuals was more in the 7% to 7.4%. We're thinking with some of the cost creep on a 28 were more in the 7.5 range, maybe a little bit higher. But then as we start doing these others with 36 stages and 100 1,000 stage, then that will start to bump the number up. And so we'll have to I mean, we're working through all that right now to try to get a feel for impact on a CapEx spend. And it's easy to just apply the number to the well count, but you got to consider timing and timing of stimulation services once you start doing 36 stages and what that means to how much capital you spend in the calendar year.
So it's not as simple as it would appear at the surface.
Sure. And then when you about the well count, 69 gross operated wells, what does that net down to on a net basis?
47. And then there's 6 47 and 6. So there's 6 net non op wells against the total program to 53, the 69 goes to 47 on strictly the operator side.
Okay, great. Thank you very much.
Hi, Bob.
Your next question comes from the line of Irene Haas
with Hunderlich Securities.
Hello, everybody. I have a question on Three Forks. Hello. Three Forks Spanish. Can you hear me?
Yes. Okay. Just excited that you guys are starting to drill it and just want to get a sense of spatially how these 5 wells are spread out and how you feel about the configuration within the Three Forks? Should we expect something probably a little more variable versus what we used in the middle Bakken? And so just a little more color on this really kind of exciting set of
The data so far would indicate that the Three Forks would be consistent within those type curve bands. As you start to move below that and we'll have some more data. It's kind of with the Brigham wells, there's a fair amount of data kind of on the east side of our western position. Obviously, with these 2 new wells that straddle the state line right around the Hebron, we'll have some really good data there. We had that 1 Continental Overt well that looks good over on the state lineup in the Red Bank block.
So, we just need some more data points. Taylor, you want to add?
So we've got actually one well in Indian Hills that's drilled but not yet completed. It's a 3 corks test. There is a test by another operator that has recently been released. It's only a month production, but it looks very encouraging.
And it's right off the southeast corner of our Indian Hills block.
Does it get better as you approach northward towards the sort of basis edge? Does it get better in terms of philosophy at least?
Least? It's really area dependent. We've done the same thing in the 3 ports that we've done in the Bakken, which is try to map hydrocarbon flow volume and ultimately a little in place. So, water saturation is important as well as thickness and reservoir quality. So, there is some variability.
To your question about where will we drill, we've got the 2 in the Hebron area. We'll drill 1 in Red Bank, 2 in Indian Hills and 1 in the southern part of the East Nansen this year. Those are the 5 wells.
Got you. How far would your footprint be from these 5 wells? How big an area are you, Blake?
I don't know if I understood how big an the area. It's
if you look at if you just go from the state line, where the 2 wells are straddle the state line over to where our well is in Indian Hill, that's roughly 3.5 or 4 townships.
Your next question comes from the line of Marty Biscow with Northland Capital.
What are you seeing for opportunities for potentially acreage acquisitions for 2011? And what kind of quality is the acreage that you're seeing? And what type of pricing are you seeing for just for
routine
land acquisition, about just for routine land acquisition about $20,000,000 We've been able to add acres in and around our blocks depending on the geographic pod anywhere from $400 to $800 an acre without brokerage costs. And it's mostly relatively small parcels,
but we have been able to supplement our blocks in
that range. Now bigger supplement our blocks in that range. Now bigger blocks typically will cost a bit more. You saw that with the Hebron deals that we did at the end of last year.
Are you seeing many potential acquisitions for bigger blocks of things that you would be interested in?
There's continue to be things that pop up. One of the things that we have to be very careful of is going out and spending a significant amount of dollars on blocks at very high per acre cost when we've got already 300,000 acres at an average cost in of $3 to $3.50 an acre and plenty of inventory to keep us busy.
Okay. And then considering that it sounds like you'll be accruing bonus throughout the year?
Yes. Michael, you want
to Yes. Our guidance is $6 to $7.50 per BOE and that does include stock based comp in that.
That does include stock based comp?
It does. That's all in.
Yes. Keith and Mike, we may want to just touch on the I mean there's a couple of different components of clarification respect to 2010 that can cause some So we have
a line item that is called stock based comp and we go through it in detail both in our S-one at the IPO as well as in the press release that you've seen. Stock based comp under that is actually a bit of an unusual item where the Oasis Petroleum Management Group or the management of the company has given part of their shares to employees. So it hits our books, but it's non cash, non dilutive to shareholders. It's not the same as normal restricted stock grants that might be given by the company. So, there is a component of that that is actually in our G and A.
And so, when we're guiding the G and A numbers, we're talking about all in with that normal stock based comp that
a company would pay. Okay.
All right. Thank you.
Your next question comes from the line of Marshall Carver with Capital One.
Yes. Just a quick question on down spacing. I know you talked about the results of the encouraging results of other operators. And I know that you're spending most of your drilling the whole acreage. But do you have any plans for any down spacing tests in the Bakken this year for Oasis operated wells?
Tyler, do you want to talk about that? Yes. We've got we don't have any plans to do any tight spacing tests this year. The focus is really on holding our acreage 1 well per spacing unit. We will drill 2 wells in fairly close proximity and plan to frac both of those wells at the same time and be microseismic.
So we are trying to get some of that data. It's not quite as tight as you might you'd see, for example, 4 wells per spacing unit, but it will close enough we'll get some of that data.
When do you plan on drilling those 2 wells?
Yes. Those will be completed later this year. 1 of them is currently drilled.
Okay. So that would be a second half twenty eleven event?
Yes.
Okay. That's it for me. Most of my other questions were answered. Thank you. Great.
Thanks, Mark.
Your next question comes from the line of Peter Mahan with Dougherty and Company.
Yes. Good morning, guys. Most of my questions have been answered as well. But one thing I didn't want to ask about is how many of your acreage is at risk for exploration in 2011, 2012? And where would that acreage be?
Yes. So we'll get some we'll have a detailed table that will be in our 10 ks. But for 2011, it's about 54 1,000 net acres is at risk. Anyway, I mean just start with that. 20 12, 24,000 net acres, we think in both cases, we can preserve all of what we want to with our drilling program.
Most of what will be exposed is more in some of the higher water cut areas over on the East Nesen side. That wouldn't be in our inventory anyway. As we think about conversion to HBP, we've got about 90,000 acres HBP currently. And with our drilling program over the next 2 years, we HBP about 60,000 acres a year. So as you get into the end of 2012, you're going to be somewhere in the $220,000,000 range.
So we
feel like we're in real good shape.
Perfect. Great. Thanks a lot for the color.
You bet. Thank you.
Your next question comes from the line of Dan McSpirit with BMO Capital.
Hey,
You mentioned the Mary Wilson and the Wilson wells at Hebron waiting on completion. Can you provide any timing on the completion date for those 2 wells and those are being completed with 28 stages, correct?
Correct. I think the Mary Wilson is currently fracking.
Correct.
I don't know what the timing is of the Wilson yet, but the Mary Wilson is the Middle Bakken well.
Right. In 2nd quarter, we don't have an exact date yet.
Okay, very good. And then the investments in the saltwater disposal line and system, just roughly what is the capital investment for that?
Total capital for infrastructure for the year is $20,000,000 So there is mostly the SWD gathering systems and SWD wells, but there is some additional capital for electrification and things like that. I don't have the exact breakout, but most of it has to be deep.
Got it. Thank you. And then one more if I could. Just generally, can you give us a sense of the rate to frac crew ratio in the basin in the Williston Basin today and how it's trending or how do you expect it to trend over the balance of 2011? Is it as high as 7 to 1 or 8 to 1?
Yes. I don't know that I've got an exact ratio, but it's clearly undersupplied right now. And based on the rig count, the way we've been looking at it is it's for all operators backlog of completions. If you stay flat on rigs from what we're hearing is going to come into the basin. The basin might be imbalanced by the end of the year.
If rigs continue to of frac stages that pushes it out in time. Okay. And then as you're adding, like we've been talking about more intensity of frac stages that pushes it out in time.
Yes, indeed. And then one more lastly here. I'm sure you see your share of property packages and I'm sure you've got a few on your desk today. Can you share with us any texture just generally on those property packages? Where are they being sourced from?
Are they more from private companies versus public companies? And if you were to add up the acreage on those same property packages that are again sitting on your desk today, what would they total?
Well, what I would say is that most of the things that we're seeing are more privately generated than public. I mean, there are some public things where people are doing cleanup or optimization work. You've seen those recently. If you were to add up everything that's floating around in the market today from an acreage basis, I don't know if I could make a good wild guess.
It's 100 of 1000 acres. Yes, probably
a couple of 100000 plus or minus.
Got it. Thank you. All the best. Thanks.
You bet.
Your next question comes from the line of Teitra Sundaram with Cardinal Capital.
Thank you. Congratulations. Great quarter. Couple of things. You talked about the delta the current CapEx budget can absorb a CAD 7 point 5 million well cost.
If you have decided to do the additional stages, about 100,000 more per stage, so that would be an additional 800,000. So I just wanted to get clear that piece is not currently in the CapEx estimate and you all are trying to get your arms around what that additionally be, correct?
Yes. So if you were to take just call it for fun, let's take 800,000 and we've got 47 net wells, then that's $38,000,000 roughly, okay? And we already had 16 wells, which would for fun, let's call it 8 or 9 in the budget. So plus you got to factor in timing. So I mean, I'm doing this off the top of my head, which is why
we're
going to come up with a plan and we're going to tell you. But I'd say that it's probably 25 ish, maybe a little bit lower $20,000,000 Taylor?
Yes, that's where it's kind of going.
Yes, it would be less.
Closer to $15,000,000 when you look at working interest in wells. And not all
of them will be $20,000,000 not all of the wells will be 26.
Correct. I don't have any to get down. So we think it's probably an incremental 15,000,000 at most by the end the year. We just need to continue to work on it.
Yes. Can you help me understand how much of those 53 wells and I apologize if you all have discussed this in the past, how many of those 53 wells that are in the CapEx budget are in the Indian Hills and the Red Bank, I think you said, area? Those seem to be the most prolific.
Yes. So we've got in so, in Indian Hills, there is 17 wells? Gross.
Gross, yes. Hold on. So you've got net numbers and he's going to give you gross and then maybe we'll net it down for you. Yes. I mean as a general rule you can use about 65%, but
Got it.
So 17 gross wells, about 12 net wells in Indian Hills. And the other area you're asking about was? Red Bank.
I think it's the Red Bank, right?
Yes, Red Bank, there's 20 9 gross wells and that is about 21 wells net.
Great. Now so just philosophically, it is not possible to go back and increase the stages on an already completed well? General
rule,
what I would
say is no. General rule, what I would say is no.
Okay.
We did actually a couple of years ago go into a well where swell packers were already set, but the well had not been fracked and pulled the liner and set it up a different way. But mechanically that's challenging with our guys were able to get it done, which I was actually a bit surprised. But it's really not practical.
Okay. And my final question was just on talking about the pressure pumping services versus the pace at which you'd like to go, assuming able to get that additional 1 to 2 crews as we go into 2012 dedicated crews. Is there anything in your control from the point of view of pumping services that would enable you to up the pace? Or is it just that you have the 2 additional crews, but you're still Siamese because services just don't keep up. So you never really get the pace that you might be looking for.
I guess what I would say is that as think about it with the next crew in the next couple of months and then potentially another one sometime in 2012. I think that pace is sufficient for us. And so that again, we try to we try not to bounce around with respect to equipment. So we try to approach it from one direction. And so as we can line up these pressure pumping services, then we'll look to add rigs.
I see. Okay. And finally 18 wells waiting for completion versus 10 a year ago, there was some discussion earlier about if weather had not been an issue. What would I'm trying to understand how much of those 18 wells reflects weather versus the issue of getting the services to complete the well?
Yes. That was actually 10 wells at the end of November versus the 18 now. And as I mentioned, our I would expect a typical run rate on backlog on wells to be somewhere in that with current rig counts to be somewhere in the 8% to 10% range. And notionally, I think you can think about the weather component of the 2018 being roughly 8
Got it. Okay. Okay. So the services are not an outsized issue other than just a normal part of the
And you have no further questions. Great.
Well, thanks for your participation in our year end call. We'll be filing our 10 ks, our first 10 ks as a public company, in fact tomorrow. And I'm proud of what all the OHS team has been able to do in terms of delivering results that we'll see in that 10 ks that will come out tomorrow. We're pleased with our solid shareholder base and are enjoying meeting new folks at conferences and industry events. We'll be at a number of energy conferences in the next couple of weeks months and look forward to catching up with many of you along the way.
Thanks again.
Ladies and gentlemen, this concludes today's conference call.