Chord Energy Corp (CHRD) 2010 Q4 法說會逐字稿

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 fourth quarter and year-end 2010 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. (Operator Instructions)

I would now like to turn today's call over to Mr. Lou. Sir, you may begin your conference.

Thank you, Celeste. Good morning, everyone.

This is Michael Lou, Senior Vice President of Finance. We're reporting our fourth quarter and year ending December 31, 2010, results today, and we're glad to have you join our call. With me today from Oasis are Tommy Nusz, President and Chief Executive Officer, Taylor Reid, Chief Operating Officer, Roy Mace, Chief Accounting Officer, and Richard Roebuck, Director of Investor Relations.

This conference call is being recorded and will be available for replay approximately one 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 latest 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-1 and as amended. We disclaim any obligation to update these forward-looking statements. Please note that our 2010 Form 10-K 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 applicable GAAP measures can be found in our earnings release or on our website.

I will turn the call over to Tommy.

Good morning, everyone, and thanks, Michael.

First, I would like to thank everyone for joining us this morning. I think it is 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 am very proud of the team that we have put together and what we have been able to accomplish. I am 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 have 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 2010 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 two rigs at the end of 2009 to six 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 six rigs in the West and one rig in the East. We grew production to 7,511 BOEs per day in the fourth quarter and ended the year with reserves of 39.8 MM BOEs. We also completed two strategic bolt-on acquisitions in Montana that we're very excited about, and we will give you some more color on what we're seeing in this area, which we call Hebron, in a minute.

When we started Oasis in 2007, we had a clear focus on oil and we have been rewarded for this decision throughout 2010 and into 2011, as our oil weighted production 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 2009 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 $243.8 million, or 70% of our CapEx, in development throughout 2010. Since 45% of our production in the fourth quarter 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 of barrels only. We continue to see our wells come into this range, and as we mentioned in our August call, our Angell 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 Angell Well Indian Hills. This area represents the deepest part of the basin and has comparatively high reservoir pressure, and also higher hydrocarbon core volume. We currently have four 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 on pads, which definitely helps our cost structure and efficiency. We are basically able to drill one well north and one well south off of the same pad in adjacent 1,280-acre drill blocks. With the wells are being drilled back-to-back, the rig can easily skid from one to the next. And as you've heard us talk about before, this set-up also helps the completion process, as we can pop one 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 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 pressure, and we estimate a slightly lower hydrocarbon core volume. So the fact that they're lower in our type curve range makes a lot of sense to us.

Now I would like to 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 fourth quarter, and now have a total of 57,000 net acres combined. We have three 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 Beula Irene, on the West side of the block, about 10 to 12 miles from the Amazing Grace. While the Beula Irene was drilled and set up by the previous operator, we actually at Oasis completed it after the acquisition.

We now have two 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 Three Forks. We are very pleased to have the Beula Irene, our furthest West Middle Bakken completion, produce 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're very comfortable that the area between these two wells will have 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 two 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 two good Three Forks 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 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 under a the acreage in West Williston that we believe is well delineated. Some of our acreage is outside the blue box, in 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 two extensional areas. The first, which we call Target, is 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 one Middle Bakken well planned in Target and two Middle Bakken wells planned in Mondac in our 2011 budget ,which should help us further delineate this acreage. Together, Target and Mondac cover about 47,000 net acres.

Since we're able to drive operations on our large contiguous block, we're working with a third party who will build and own gathering lines and related infrastructure in these three areas -- 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 third quarter 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, on the infrastructure side, we are investing in salt water disposal lines and disposal wells to reduce our LOE. If you truck water, it typically costs about $2.50 to $3 per barrel of water, but with this infrastructure we can dispose of our water -- or produce water for less than a dollar per barrel.

Now let's shift our focus over to East Nesson, where we have been running one rig and will continue to run one rig throughout 2011. We are maintaining our gross reserves average between 350,000-barrels and 600,000-barrels of oil only, or on an equivalent basis 400,000 to 675,000. Although this area is still in early stages of development, our East side wells within our core area 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 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 arched 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 390 BOEs per day, only down slightly from the first 30 days of 441 BOEs per day. That second 30 day rate puts the Ernst Well's performance well within the type curve band, and somewhere in the 400,000-barrel range.

Across all of East Nesson we expect to drill ten gross operated wells in 2010. As of March 1, we have 12 operated wells on production, and had another three operated wells waiting on completion, and our one rig in the East Nesson was drilling the rude, which is the southern most -- in the southern most 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 fourth quarter increased to 1,900 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 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 Three Forks wells per spacing unit from two to three, which could potentially add another 86 gross wells to our inventory.

Now that we have covered operations and well performance, I would like to direct our discussion to a couple of more macro issues. Not that it is 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 first and second quarter of 2011. 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 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 and 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 million to $7.4 million for a 28-stage job, but we think that well cost currently should be more around the $7.5 million 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 has WTI at $78 per barrel, and just last week we put on a two-way collar for 1000-barrels a day for the rest of the year at 95 by 117, when the swap rate was above $103 per barrel. So while we do have some service costs 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 seventh rig in a few weeks, we will have to make sure we can match frac swaps 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 will wrap up my comments with another broader discussion about the decisions that we have made based on some science work we've been doing across our operations. We are primarily completing our wells, 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 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&D costs should be in the $6 to $8 per barrel range, some of the most efficient capital that we can spend. We are deciding to go ahead and complete the majority of our remaining operated wells with 36 stages for the remainder of 2011, with the focus specifically on Indian Hills and the southern part of the East Nesson block. When we think about acceleration, which plenty of folks have been asking us about, this really is the most efficient acceleration that we can do with the additional capital that we raised in February.

Now the next obvious question you will have is the impact on production to 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 seventh 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 three dedicated frac crews sometime in 2012. So it is 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 re-fracs. We would 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 is really nothing that you haven't already heard from us. We reported reserves and updated operational ranges for 2010 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 million of debt which would give us, on a pro forma basis, just over $530 million of cash and $670 million of overall liquidity as of December 31, 2010. We expect our current liquidity will fund all of 2011 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 fourth 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 and our aggressive drilling program, we are putting in additional financial hedges, like Tommy said, and we continue to evaluate and add rail deals on gross operated volumes, in order to protect against some of the downside commodity risk. Concerning rail, you may have seen the latest presentation on the North Dakota Pipeline Authority website, which is slides from the February 28 North Dakota's crude oil rail transportation infrastructure webcast. It has some information about 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 third quarter to $7.92 per BOE in the fourth quarter. This was really just making sure that we are fully accrued for operating expenses. We continue to see LOE decrease in 2011, down into the $5 to $7 per BOE range. G&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 have 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 five times to $82.2 million. 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.

(Operator Instructions) Your first question is from the line of Dave Kistler with Simmons and Company.

Hello, guys.

Good morning, Dave.

Real quickly, on the 18 wells that are drilled and waiting on completion, you mentioned that weather is the primary component there. Has access to services been a challenge? And you talk about adding an additional frack 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 it is 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 at a lot of things, and as I mentioned, we have a lot of interesting alternatives to consider. But 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 in the first quarter. So, we're always going to have a bit of a backlog, which I think is fine, call it 8 to 10 wells, but it is 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 first production kind of times look like? Are they -- in the past, you've talk 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 is going to grow a bit.

Okay. That's helpful.

At least in the near term, Dave. Ultimately, I think we 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 five-year period?

Yes. Taylor's -- I think Taylor's got that.

So, you're talking about capital for our PEDs?

Exactly.

Yes. So, there's total capital for all of our booked PEDs are just under $350 million. So, when you look in gross well count is 124 net wells, 53. So, when you look at cash flow over the five-year period with that plan, it's still -- 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 is 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 million a year. And EBITDAX for last year was $82 million, if you use our fourth quarter run rate it would be about $120 million. So, we're clearly covered.

Great. That clarification is very helpful.

You bet.

I will let somebody else jump on, guys.

Okay. Thanks.

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

Good morning, Ron.

A couple questions. You did a good job of walking through your individual areas, both West Williston 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 400,000 to 700,000 barrels that you've used for West Williston, is that also being applied to the Montana acreage as well?

Yes, Ron. It is -- in essence, it's about 14% of our CapEx. And as we talk about, one rig programs typically will consume about $50 million per year, and we expect to run one rig over there. So, I think our actual CapEx is around $60 million. So, it's a little bit higher than that, with some other 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 have mentioned, with the 400,000 to 700,000 type curve range early days, but looks like the wells, 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 know, 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 a 36 stage fracks in even the Montana, and 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 frack 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 we did over on the East side in East Nesson, remember, was I think 25 plug-in per stages and 11 leads or something, may not be exact, but it's close to that. So, I think you will 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 is yourselves or third parties building out infrastructure. What's the timeline of that? And I am assuming you're talking about both clean and dirty water and gas lines being put in, relative to your development plan.

Yes. Taylor, do you want to pick that up?

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 third quarter. The infrastructure for salt water disposal, we've got ongoing projects in Red Bank, with two 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 fourth quarter.

And is that one of the things that will then drive that LOE down, as we -- as we move through the course of the year?

Correct.

Great.

As Tom said, it will haul water. It is about $2.50 to $3 a barrel. When we get our systems in place, you'll cut the cost to under a dollar a barrel, so it will drive down LOE quite a bit.

Great. All right, guys, let me let someone else jump in. Thank you.

Thanks, Ron.

Your next question comes from the line of Oliver Doolin 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 are looking at hedging?

I will let Michael pick that one up.

Sure, Oliver. Right now, we have 7,000 barrels a day hedged in 2011. We've got mainly collars and three-way collars. And, then you heard Tommy talk about, we're putting in more each day, and just kind of layering them on. More recently, we have been focused on between $80 and $95 floor levels, just given the run up in the oil price. But if you think about it from a couple standpoints, if you look at it compared to fourth quarter, we're basically, for 2011, at our fourth 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 the expected production will likely be much higher than those levels, so we'll 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, five, roughly five Three Forks wells.

Great. Thank you. That's all I had.

Great. Thanks.

Your next question comes from the line of Derek Whitfield with Canaccord.

Good morning, guys.

Good morning, Derrick.

High level question for you, in thinking about your current liquidity and development plans, I am interested in your thoughts on accelerating development beyond the current programs. 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've talked about, first 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 have always talked about, we want to make sure that we have enough pressure pumping services to support rigs that we bring on, because we don't want to drill a bunch of wells 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, you know, we'll have two 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 a bit over 60. And so far, the guys spent a lot of time on it, as you can imagine doubling head count in six 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, to accommodate that -- on the manpower side.

Got it. That makes sense. And then, could you comment on the preliminary data you are 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 out to the Three Forks objective versus the Bakken?

Want to pick that up, Taylor?

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 tests on the West side, really across all of our acreage position, to tell you how the Three Forks will perform relative to the Bakken yet. And so, as we get to the end of this year and we've got the five wells we have been talking about tested, we are going to have a much better indication of relative performance.

Okay. That'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 is 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 third parties and we end up with being indexed either off of WTI or Clear Brook, for the most part. So, we don't yet have a lot of closure to LLS, but something we're looking at.

But the other thing to keep in mind is that that differential, you know, WTI to LLS differential, is run up pretty good in the last few months, but just given the timing of how it's run up, it is pretty volatile. So, what you don't want to do is run out and spend a whole lot of capital to solve something that is a short-term blip, if that's the way it turns out.

Yes. That's 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.

Good morning, Steve.

I was wondering if you could touch on any thought you might have on density drilling, with Brigham talking for Bakken and for Three Forks per 1280, what 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 is a minimum of three and likely four. Fortunately, we'll have some good information here over the next twelve months to verify that, but just notionally as you think about it, as we talked about before, with three wells you get what we estimate, based on our sub service 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. Earlier days on the Three Forks, so you know we just, as we talked about, we saw Brigham -- or I am sorry, Whiting say that they're going from two to three. So, we have a fair amount of data, though, within Sanish. So, it looks like it is moving in that direction as well, but it is just too early to kind of throw down a number and say it is absolutely that.

Okay. And if you touched on this, I apologize, but any plans on further testing the Burke County acreage where you drilled the [Revnee] well?

I don't think that we have got anything in this year's capital program with the Revnee. 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 is 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 36 stage fracks, are you spacing those tighter, or are you now drilling laterals that are longer than 10,000 foot?

No, it is tighter spacing. The laterals are still 10,000.

Okay. And did you say that all your Bakken wells this year would be 36 stage?

Yes. 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 is only so much we can do, obviously, but going forward, the majority of them will be 36 stages. Is that fair?

Yes, yes in those two areas and then we continue 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 30/60?

Yes. On a net basis, I think we can call it roughly 100,000 to 120,000.

Okay. And then, when you said your budget reflected $7.5 million per well for -- that it corresponded to 24 stage frack, with most of these wells, a lot of these wells being 36 stage, then we need to incorporate a little bit higher well costs on average in the budget than that $7.5 million, is that correct?

Yes. The 7.5 -- when we -- our typical design has been $7.2 million to $7.4 million, 28 stages. I think you said 23 or 24.

28, yes.

But it's 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 have the wells and then the type curve ranges, we play with a lot of things, including concentrations per stage and compositions per stage, and some places, we use all white sand. But as we came into the end of last year, first of this year, end of last year really, it was what we saw in actuals was more than $7 million to $7.4 million. We're thinking with some of the cost creep on a 28, we're more in the $7.5 million range, maybe a little bit higher.

Yes.

But then as we start doing these others, you know, with 36 stages and $100,000 a stage, then that will start to bump the be number up. And so, we'll have to -- we're working through all of that right now, to try to get a feel for impact on a CapEx spend. And it is easy to just apply the number to the well count, but you have to consider timing.

Yes.

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 is not as simple as it would appear at the surface.

Sure. And then when you talk about the well count, 69 gross operated wells, what does that net down to, on a net basis?

47.

47. Great.

And then there's six, 47 and six. So, there's six net non-op wells. It gets the total program to 53. The 69 goes to 47 on strictly the operated side.

Okay. Great. Thank you very much.

All right, Bob.

Your next question comes from the line of Irene Haas with Wunderlich Securities.

Hello, everybody.

Good morning.

Hello. I have a question on Three Forks Sanish. Can you hear me?

Okay. Yes.

Okay, just excited that you guys are starting to drill it, and just want to get a sense of spatially how these five 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're used to in the Middle Bakken, and just a little more color on this really kind of exciting sets of ( inaudible).

At a macro level, what I would say is, based on what we have seen, at least on the West side, with some of the Brigham wells, that 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 is kind of, with the Brigham wells, there is a fair amount of data, kind of on the East side of our western position. Obviously, with these two new wells that straddle the state line, right around the Hebron, we'll have some really good data there. We had that one Continental Obert well that looks good, over on the state line, up in the Red Bank block. S,o we just need some more data points. Taylor, do you want to add to that?

So, we've got actually one well in Indian Hills that's drilled but not yet completed that's a Three Forks test. There is a test by another operator that has recently been released. It's only a month's production, but it looks very encouraging.

And it's is right off the southeast corner of our Indian Hills block.

Does it get better, as you approach northward towards the sort of basin's edge, does it get better in terms of velocity at least?

It is really area dependent. We have done the same thing in the Three Forks that we have done in the Bakken, which is try to map hydrocarbon floor volume from (inaudible) plates. 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 two in the Hebron area, we'll drill one in Red Bank, two in Indian Hills and one in the southern part of the East Nesson this year. Those are the five wells.

Got you. How far will your footprint be from these five wells? How big an area are you blanketing?

How big the area is?

If you look at -- if you go from the state line where the two wells are -- straddle the state line over to where our well is in Indian Hills, that's roughly 3.5 to 4 townships.

Okay. Great.

Okay?

I'm sorry. Your next question comes from the line of Marty Beskow 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 potential add-ons of acreage?

Yes. So, this year we have got budgeted, just for routine land acquisition, about $20 million. We have been able to add acres in and around our blocks, depending on the geographic pod for anywhere from $400 to $800 an acre, without brokerage costs. And it is 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?

You know, there's a -- 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 have already 300,000 acres at an average cost in of $300 to $350 an acre, and plenty of inventory to keep us busy, so.

Okay. And then also, for your G&A outlook for the year, what is your current guidance for G&A, excluding stock-based comp, considering that it sounds like you will be accruing bonus throughout the year?

Yes. Michael, do you want to --

Yes. Our guidance is $6 to 7.50 per BOE, and that does include stock-based comps in it.

That does include stock based comp?

It does. That's all in.

Yes. Keep in mind -- Mike, we may want to just touch on this. There is a couple of different components and clarification, with respect to 2010, that can cause --

So we have a line item that is called stock based comp, and we go through it in detail, both in our S-1 at the IPO as well as in the press release that you have 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 is non-cash, non-dilutive to shareholders, it's not the same as kind 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&A, and so, when we're guiding to G&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 hold acreage, but do you have any plans for any down spacing tests in the Bakken this year? -- for Oasis operated wells?

Taylor?

Yes. We have got -- we don't have any plans to do any tight spacing tests this year, the focus is really on holding our acres, one well per spacing unit. We will drill two wells in fairly close proximity, and plan to frack both of those wells at the same time, and be micro seismic. So, we are trying to get some of that data. It is not quite as tight as you might think you'd see, for example, if four wells per spacing unit, but it'll -- close enough we'll get some of that data.

When do you plan on drilling those two wells?

Those will be completed later this year. One of them is currently drilled.

Okay. So, that would be a second half 2011 event?

Yes.

Okay. That's it for me. Most of my other questions were answered. Thank you.

Great. Thanks, Marshall.

Your next question comes from the line of Peter Mahon with Dougherty and Company.

Yes. Good morning, guys. Most of my questions have been answered as well, but one thing I did want to ask about is how many of your acreage is at risk for expiration in 2011 and 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-K, but for 2011 it is about 54,000 net acres is at risk anyway, 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 water cut areas over on the East Nesson side that wouldn't be in our inventory anyway. As we think about conversion to HBP, we've got about 90,000-acres HPP currently, and with our drilling program over the next two 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 range,.

Perfect.

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.

Gentlemen, good morning.

Good morning, Dan.

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 two 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.

And Wilson's in second quarter. We don't have an exact date yet.

Okay. Very good. And then, the investments in the salt water disposal line and system, just roughly what is the capital investment for that?

Total capital for infrastructure for the year is $20 million. So, it 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 it. Thank you. And then, one more if I could. Just generally, can you give us a sense of the rate to frack crew ratio in the basin, in the Williston Basin today, and how it is 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 have got an exact ratio, but it is clearly under supplied right now. And based on the rig count, the way we have been looking at it is, it's for all operators, backlog of completions, if you stayed flat on rigs, from what we're hearing is coming into the basin, the basin might be imbalanced by the end of the year. If rigs continue to pick up, and you get more increases, it is going to take longer. And as you're adding, like we have been talking about, more intensity of frack stages, that pushes it out in time.

Yes. Indeed. Indeed. And then one more, lastly here. And I am sure you see your share of property packages and I am sure you have got a few on your desk today. Can you share with us any texture of 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?

Wow. What I would say is that most of the things that we're seeing are more privately generated than public. There are some public things where people are doing clean up or optimization work. You have seen those recently. If you were to add up everything that is floating around in the market today from an acreage basis, I don't even know if I could make a good wild guess.

It is hundreds of thousands of acres.

Probably a couple hundred thousand plus or minus.

Got it. Thank you. All the best. Thanks.

You bet.

Your next question comes from the line of Chitra Sundaram with Cardinal Capital.

Thank you. Congratulations. Great quarter. A couple of things. You talked about the delta, the current CapEx budget kind of saw over 7.5 million well cost. If you 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're 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 is $38 million, roughly.

Yes.

Okay? And we already had 16 wells, which for fun let's call it eight or nine in the budget, so plus you have to factor in timing, so I mean, I am doing this off the top of my head.

Yes.

Which is why you come up with a plan and we'll tell you. but I would say that it is probably 25ish, maybe a little bit lower, $20 million, Taylor?

Yes, that's where I was kind of going, yes.

More or less.

Probably closer to $15 million, when you look at working interest in wells.

And not all of them will be 20 -- not all of the wells will be --

Correct, correct, how many you get done. So, we think it is probably an incremental $15 million 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 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? Because those seem to be the most prolific.

Yes. 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 is going to give you gross.

Yes.

And then maybe we will net it down for you.

Yes, and I can --

Yes.

As a general rule, you use about 65%, but.

Got it.

17 gross wells, about 12 net wells in Indian Hills, and the other area you were asking about was --?

Red Bank.

I think it was the Red Bank, right?

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 an 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 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. Our guys were able to get it done which I was actually a bit surprised, but it is really not practical.

Okay. And my final question is just on talking about the pressure pumping services versus the pace at which you would like to go, assuming you're able to get that additional one to two crews as we go into 2012, dedicated crews. Is there anything in your control, from the point of your pumping services, that would enable you to up the pace, or is it just that you have the two additional crews but you're still stymied, 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, 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.

Got it.

And so that again, we try to -- try not to bounce around with respect to equipment. So, we try to approach it from one direction and so, as we can lineup the pressure pumping services, then we'll look to add rigs.

I see. Okay. And finally, 18 wells waiting for completion versus ten a year ago. There was some discussion earlier about if weather had not been an issue, what would -- I am trying to understand how much of those 18 wells reflect weather versus the issue of getting the services to complete the well?

Yes.

It was actually about ten.

Yes. That was actually ten 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 the -- with current rig counts, to be somewhere in the 8 to 10 range. So, notionally I think you can think about the weather component of the 18 being roughly eight.

Got it. Okay. So the services are not an outside issue, other than just 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-K, our first 10-K as a public company in fact, tomorrow. And I am proud of what all the Oasis team has been able to do in terms of delivering results that we'll see in that 10-K 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 and 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. You may now disconnect.