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Executives

Michael Lou – SVP - Finance

Thomas Nusz – Chairman, President and CEO

Analysts

Brian Lively

Michael Hall

Scott Wilmoth

Derrick Whitfield

Don Crist

Taylor Reid

Irene Haas

Jason Wrangler

Gail Nicholson

Martin Beskow

Peter Mahon

Chitra Sundaram

Jack Aiden

David Snow

Oasis Petroleum Inc. (OAS) Q1 2011 Earnings Call May 12, 2011 11:00 AM ET

Operator

Good morning. My name is Tiffany and I will be your conference operator today. At this time, I’d like to welcome everyone to the First Quarter 2011 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.

Thank you. Mr. Lou, you may begin your conference.

Michael Lou

Thank you, Tiffany. Good morning, every one. This is Michael Lou, Senior Vice President, Finance. We’re reporting our first quarter ending March 31st, 2011 results today and we’re pleased to have you on our call. Joining me today from the Oasis team are Tommy Nusz, President, Chief Executive Officer; Taylor Reid, Chief Operating Officer; Roy Mace, Chief Accounting Officer; and Richard Robuck, 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 included our latest financial and operational results in our May investor presentation which will be on our website after the call.

Additionally, much of the detail that we shared on our year-end call will now be included in the appendix of our investor presentation, particularly on specific pods in the West Williston and details regarding infrastructure development, so feel free to refer to it for further 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 Annual Report on Form 10-K and our quarterly reports on Form 10-Q. We disclaim any obligation to update these forward-looking statements. Please note that we expect to file our first quarter 10-Q 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’ll now turn the call over to Tommy.

Thomas Nusz

Good morning and thank you for joining us this morning to discuss our first quarter financial results and more recent operational activity. I’ll dive right into our operational update and then hand the call back over to Michael to wrap up with a few comments on financial highlights.

We grew our production from 7,500 Boes per day in the fourth quarter up to approximately 8,100 Boes per day in the first quarter, which is right where we thought we would be when we spoke back in March. Our operations team did a great job, working through a brutal winter, and we managed to grow production by 8% this quarter over the fourth quarter of 2010.

This growth came in spite of the fact that we had planned on completing 18 gross operated wells in the first quarter and actually completed only 8 gross operated wells. That eight gross operated wells translates into 5.5 net wells, which is only 12% of our target 47 net operated wells for the year. So we clearly have some catch-up work to do.

In total – that is, including the non-operated wells – we placed on production 23 gross, 6.4 net Middle Bakken and Three Forks wells in the quarter, and had 47 gross or 20.6 net wells drilling or in the process of completing at the end of the quarter.

We ended the quarter with 23 gross operated wells waiting on completion and we currently still have 23 gross operated wells waiting on completion as of May 10th, so a bit higher than we’d like to have and I’ll come back to that in a minute.

We now have seven rigs running with the delivery of a new rig from Nabors which has just spud and is drilling the Bay Creek Federal one of our extensional test on the west side of the basin in our Mondak area. So we now have six rigs in the west and one in the east.

We continue to upgrade our fleet to newer generation rigs that will help us to be more efficient once we start getting into more full-scale pad development. While we’re still scheduling 10 wells per rig per year, we have continued improvement on our spud to rig release cycle times. In fact, we have 18 wells in our 2011 drilling program so far that have rig released, and of those seven were 22 days or less for spud to rig release. So our team is doing a great job, improving our drilling efficiency.

The critical path item for us right now, though, is frac crews. Starting in mid-April we secured our second dedicated crew. Since we’re now transitioning to 36 stage completions as our base well design, our frac intensity is increasing. Said another way, we can typically do about three and-a-half to four wells per month with one crew with a 28 stage plug and perf job in decent weather, I might add. We now expect to complete three to three and-a-half wells per month with 36 stage completions. We definitely expect our two crews to become more efficient over time.

We did have as an example and before winter weather hit our dedicated crew complete a 36 stage job in just five days excluding move and set-up time.

With two crews, we’re pretty much balanced with our seven-rig program, assuming we are completing all of our wells with 36 stages. But with that, we’re not working down our wells waiting on completion to what we think is generally our base level of about 8 to 10 projects at any point in time waiting on completion.

The simplest solution for us, at this point, is to lock up an additional dedicated frac crew, which is what we currently expect to do. We are currently in discussion with a few viable options for additional frac capacity and would expect to see a third dedicated crew within the next 12 months, but I’d not be surprised to see that show up as early as this summer.

That new crew should be able to work off our remaining inventory in about a quarter or so. Once the inventory is worked down and given our significant cash position, we will then have a lot of flexibility to increase our rig count. It would not be unrealistic, under that scenario, to see us get to eight to nine rigs by the end of 2011, assuming we pick up the third crew in the third quarter and start to work down our backlog.

Just to be clear, even if we do add a rig or two in 2011, I wouldn’t expect to have much new production from this acceleration in the 2011 calendar year due to the timing of the rigs showing up and subsequent completions.

Like we said in March, the real immediate and most effective acceleration comes from moving the majority of our wells from 28 stages to 36 stages. As we get into 2012, depending on how efficient we are, you could see us potentially add one more frac crew and get into the 12-rig neighborhood later in that year.

From a cost standpoint, moving to 36 stages makes perfect sense, as it’s the most efficient capital that we can spend. That being said, as we make this shift, a portion of the economic benefit is being offset by continued upward pressure on overall well cost.

Prior to the harsh winter we were seeing about $7.5 million per well for 28-stage plug and perf completion. More recently we’ve seen this base cost escalate by about 10%. This is partially due to adverse operating conditions in the basin itself, as we experienced significant snowfall, ground thawing and variable weather conditions.

We’re also seeing some real cost inflation associated with completion and pressure pumping services and specifically in materials like proppant. Obviously, some of this has to do with oil price which has increased 45% just since our IPO last June. Hard to break down all of the drivers to cost inflation, but we do think it’s prudent at this stage to increase our routine well cost estimate for a 36 stage completion into the 8.5 to $9 million range. And we will see where things go from here.

Our team has done a great job of identifying ways to be more efficient and to mitigate cost creep and we are furthering our relationships with our key service partners. We believe there may be some other creative solutions to optimize well costs as well in the future.

One of the ways we’ve done this is by modifying our engineering design. We’re also taking over the reins on a few of the service input components to our capital cost structure and will continue to look for more of that given current service cost escalation, that in effect takes the economic benefit gained from our efficiencies and transfers that to the service companies and becomes an embedded part of our overall cost structure for years to come. Some of these costs are real but some are just driven by market conditions and we’re looking for ways to mitigate that through the power of our inventory.

We’ve now developed some key relationships to build out our oil and gas gathering infrastructure. As we went down the path of establishing gathering on our large contiguous acreage blocks, we were actually able to agree on some very balanced terms with third parties for both oil and gas gathering systems.

Based on agreements we’ve put in place for gas gathering, we should expect to see natural gas sales from that gas gathering effort in the third quarter for Indian Hills, Red Bank and Hebron all on the west side of the basin that will add about 4 to 5 million per day net to our gas volumes. Possibly, some of those wells could come on as early as the second quarter.

Later in the year, we should also expect to see gas sales from wells in the area we call Cottonwood in our East Nesson position. Given the high BTU content of the gas in the basin, we expect to still clear north of Henry Hub pricing for gas production, even after the percentage of proceeds that we will pay to third-party gatherers. We should see our total net gas production increase to 8 to 10 million per day net in the fourth quarter, but keep in mind we’ve already factored that into our annual guidance.

Additionally, we recently executed an agreement with a midstream company to connect our wells in the Indian Hills, Red Bank and Hebron – again, all on the west side – to their oil gathering system. That project is expected to be in service in the first quarter of 2012 – possibly, the fourth quarter of 2011, which will be ideal, if we could have it in before next winter.

We’ll pay a fee per barrel on these lines, but we will reduce net 1 to $2 per barrel of trucking cost to get our oil from the wellhead to multiple pipe and rail delivery points. That will give us a lot of flexibility on optimizing price, and with that, we will likely start taking over more marketing responsibility internally.

Conversely, but still focusing on infrastructure, we’re investing most of our $20 million of infrastructure capital on salt water disposal lines and disposal wells to reduce our LOE. We now have a total of two disposal wells tied into our disposal system. We just completed the drilling of a third. And we expect to have a total of six disposal wells by the end of the year.

If you truck water, it typically costs about $2.50 to $3 per barrel of water. But with this infrastructure, we can dispose the water for around $1 a barrel. We will see the effects of that over time and we should see LOE trend down more into the $5 to $6 per BOE of the production range, but again, that’s also factored into our guidance.

As for overall impact of everything that I’ve been talking about thus far, it’s really too early to formally change our current $490 million E&P budget, but with us going to all 36 stage completions, and associated cost pressures, there’s probably more upward pressure on that number than downward pressure.

Given the variability and the timing of when new frac crews start and when new rigs show up, especially when none of those contracts are signed today that we don’t want to put out a large range today. But probably fair to say that if we can get a break on the weather front, we can secure a third dedicated frac crew this summer and we add additional rigs prior to the end of the year. Our capital spend could end up being somewhere in the $550million range.

As we’re now almost halfway through the second quarter, we have a little more visibility into this quarter’s production. While we’re pleased to get our production number in the first quarter, especially given the growth we delivered, it will no doubt be harder, but not out on the range of possibilities for us to be around the bottom of the range or 9800 Boe per day for the second quarter, given the prolonged wet weather.

Like I said earlier, we’ve had some tough conditions as winter turned into spring and as a few late winter storms significantly disrupted operations for us and everyone else in the basin, as you probably heard over the last week. All that being said, we still think we’ll be in good shape for the full year but we plan on giving you more color regarding that back half of the year, both in terms of production and capital, on our August call.

With that, I’ll turn the call back over to Michael to discuss our financial results.

Michael Lou

Thanks, Tommy. As you might expect we spent substantially less capital in the first quarter than expected with only $76 million of the $123 million budgeted for the first quarter. This delay in spending is due primarily to weather delay that Tommy discussed previously.

We ended the quarter with $470 million of cash and short-term investments, on the heels of raising $400 million of long-term debt. We have a strong balance sheet and will be rapidly de-levering the business as we grow EBITDA in the coming years.

We’re in a great position to fund the third frac crew Tommy mentioned and the rigs that will potentially follow with the cash on the balance sheet as well as cash flow without needing to raise additional capital. The near term commodity environment has provided additional cash flow from operations, and we also have hedged a fair amount of production in 2011 and 2012 to protect the base level drilling program that will protect our leases even in a lower oil price environment. We have about 8500 barrels per day hedged in 2011, and another 6500 barrels a day hedged in 2012.

In the first quarter of 2011, we had a realized oil price of $82.33 per barrel, which included a 13% differential for the quarter. As many of you have noticed, the Bakken is currently experiencing better differentials at Clearbrook and Guernsey, which will result in higher realized prices in the second quarter.

Production was up 8% in the quarter to 8,090 Boe per day, LOE increased $0.24 to $8.16 per Boe in the first quarter compared to $7.92 per Boe in the fourth quarter. Primarily due to the incremental costs that we incurred operating through the harsh winter. We continue to expect our full year LOE to end up between 5 and $7 per Boe.

In conclusion, we had a great first quarter and expect to deliver another year of production growth north of 100%.

With that, we’ll turn the call over to Tiffany to open the lines up for questions.

Question-and-Answer Session

Operator

(Operator Instructions) Your first question comes from the line of Brian Lively. Please be sure your computer speakers are muted prior to asking your question.

Thomas Nusz

Good morning, Brian.

Brian Lively

Good morning, guys. Tommy, just want to get some more color on the CapEx and the – I guess the forward-looking potential 550 number. Are you guys still planning to complete 53 net wells this year?

Thomas Nusz

Yeah. So if you look at – if you recall, we had 47 net operated and 53 total in the first quarter, and so the difference is the non-op. In the first quarter, and so the difference is the non-op. In the first quarter, we had about 1.5 net wells. If you annualize that, that gets us back to the six.

So let’s focus on operated. So, 47 for the budget. Without the third dedicated frac crew, we’re probably going to be somewhere in the 41 or 42 net well range. If we’re able to get that third dedicated frac crew and get caught up, then that will put us back to the 47. And from a scheduling standpoint, we had 5.5 net operated wells in the first quarter. So I would probably spread the difference out evenly over the next three quarters.

Brian Lively

Right. And so, my question then on that is if you are able to get that third frac crew in and you’re able to wind down the number of uncompleted wells, maybe by nine or so, it seems like within your – it’s hard for me to see how you get to the $550 million of total CapEx, even with 9 million well costs. Are there some other costs embedded in that estimate?

Thomas Nusz

Yeah. So if we get the third crew this summer, and we’re hedging a little bit because we don’t know exactly when. Hopefully, we’ll get it this summer. Don’t know exactly if we’re going to be able to secure that or when it’ll show up. But with going to all 36 stages on our completions and with cost creep, if we don’t get the third crew, we’re probably going to end up somewhere around our original budget number.

If we get the third frac crew and we can work off the inventory, we’ll be more in the 520 to 530 range, call it. And then the difference between that and the 550 would be incremental rigs, and again, we don’t have any contracts signed at this point. So a lot of good options, but that will be dependent on when we get those contracts signed and when those rigs show up. So we’ve got to get the frac crews first because it doesn’t make any difference – doesn’t make any sense for us to pick up more rigs if we can’t complete the wells.

Brian Lively

Right. And then thinking about the 36 frac stages, what is the incremental production that you’ll see over the first few months versus the 30 frac stages that you guys were completing previously?

Thomas Nusz

I don’t know if we’ve got that incremental.

Michael Lou

Yeah, I think what we’re seeing, though, Brian, is that with the 30% more completions from a 28 stage to 36 stage, we’re expecting kind of 20 to 30% increase in EURs and so that whole production curve we think is going to be moving up by 20 to 30% from where it’s at currently.

Brian Lively

So is it fair to assume, then, for a $550 million budget, or even $520 million budget, your production even with weather issues in the first two quarters, wouldn’t your production then most likely be at the high end of that range, your full year range that you’ve already guided to?

Michael Lou

Yeah, just remember, Brian, that with – obviously the production’s moving to the second half of the year. But it takes a lot in those last couple quarters to make up for the first half being lower. So the exit rate will be higher than what we expected at the beginning of the year but we’ll have to make up some of the volumes that we lost in the first part of the year.

Brian Lively

Okay. And so getting that frac crew on early would really drive those volumes higher I guess is the take-away from that.

Michael Lou

Correct.

Thomas Nusz

You bet.

Brian Lively

That’s all I’ve got. Thanks, guys.

Thomas Nusz

Thanks, Brian.

Operator

Your next question comes from Michael Hall. Please be sure your computer speakers are muted prior to asking your question.

Thomas Nusz

Good morning, Michael.

Michael Hall

Good morning, guys. Just curious I guess on the frac crew, can you give us any additional color on any sort of discussions you’re already having or how far along you are in the process of securing a crew, I mean, has there one been identified in particular that you’re trying to contract for or just any additional color on that?

Thomas Nusz

Yeah, we’re pretty far along in those conversations already. So it’s not like we’re starting today from scratch. And we’ve got a couple of very viable options which originally if you were to step back a couple of months ago; we were calling it 12 to 18 months. That’s why by virtue of those discussions that we’re talking about being able to hopefully line that up this summer. So it’s pretty far advanced.

Michael Hall

Okay. And then I guess the other piece just curious on, the cost inflation, you know, can you kind of split out what’s the pieces of that cost inflation look like I mean is it predominantly materials in the basin or is it still being dominated by pressure pumping, the actual contracting of that?

Taylor Reid

The biggest single component is pressure pumping. Materials is a big piece of that.

Michael Hall

Okay. That’s about all I’ve got. Thanks.

Thomas Nusz

Thanks, Michael.

Operator

Your next question is from Scott Wilmoth. Please make sure that your computer speakers are muted prior to asking your question.

Thomas Nusz

Hi, Scott.

Scott Wilmoth

How’s it going? Point of clarification on the gas gathering on the West Williston, is that an incremental 4 to 5 million a day or is that company-wide and has that been included in guidance already?

Thomas Nusz

Yeah, that 4 to 5 is incremental and that is in our guidance, the 8 to 10 that I mentioned the end of the year would be total.

Scott Wilmoth

Okay. And then does that 8 to 10 include anything on additional on the East side on gas gathering?

Thomas Nusz

A little bit, but not a whole lot, just due to timing of that project.

Scott Wilmoth

Okay.

Thomas Nusz

Not as far advanced as the other, but there is a little bit in there.

Scott Wilmoth

Okay. And then can you just lay out over the next couple of years just your acreage hold by production and drilling schedule, what you guys kind of expect over the next couple of years?

Thomas Nusz

Yeah. So what we’ve talked about in the past is if you factor down of the 300,000 acres, that which is captured within our drill block inventory, it brings it down to about 220,000 acres or so. We’ve got 90,000 acres that was HBP at the end of last year and we preserve about – with a seven rig program, we preserve about 60,000 acres per year. So that would make it to where if you got to the end of 2012, right into the first quarter of 2013, we’ve basically got everything held.

Scott Wilmoth

Okay. That’s helpful.

Thomas Nusz

And that’s with seven rigs. So if we start bumping that rig count up, then obviously it just starts pulling all of that forward.

Scott Wilmoth

Okay. And then lastly, just what are your latest thoughts on potential bolt-on acquisitions?

Thomas Nusz

Yeah, we’re – I wouldn’t necessarily count on a whole lot of that. We still participate in some block acreage deals in and around our core positions, but that’s getting more-and-more difficult as time goes on. So it’s just extremely difficult to predict. We try to be disciplined about it and so our probability of success is probably going to be a bit low, and so you just never know when you may be able to capture one of those things.

Scott Wilmoth

What about thoughts on entering other basins outside the Bakken?

Thomas Nusz

We’re not spending a whole lot of time on outside the Williston at this point. We’ve kind of got our hands full, especially as we start to look at adding a third frac crew and potentially additional rigs and at some point it’s going to make sense for us to get some people focused on that, but that’s probably – that’s not five years from now. But it’s probably 12 months from now. That way, we can position ourselves to be able to be opportunistic if the right things present themselves.

Scott Wilmoth

Okay. Great. Thanks, guys.

Thomas Nusz

You bet.

Operator

Your next question is from Derrick Whitfield. Please make sure your computer speakers are muted before entering – prior to asking your questions.

Derrick Whitfield

Good morning, guys. Just a few questions for you on the development front. Tommy, based on your earlier comments, it appears that you guys are operating an approximate call it three to four rigs per frac crew ratio and really thinking that a little further and outside of adding additional crews, are there any other initiatives you could effect that could push that towards a four to five per frac crew ratio?

Thomas Nusz

Taylor may be able to provide more color on that. Keep in mind that we’re transitioning basically all of our wells to 36 stage plug and perf. We are playing with a few combinations of plug and perf and sleeves but to really start – I think at this point we’ve got to get these frac crews operating on a continual basis and operating efficiently before we’re willing to say that we can bump that number up.

Derrick Whitfield

Okay. And then maybe taking part of that answer a little further, have you guys evaluated any of the new sliding sleeve technologies?

Thomas Nusz

Yeah, we’re familiar with what’s going on there. Our completions guys are looking at it but we haven’t done any of that yet and so we’ll watch it and see if it makes sense. At this point, though, we’re still focusing on plug and perf because at least inside the pump, inside the pipe, we know where the fluid’s going.

Derrick Whitfield

Okay. And then staying on the development topic for a moment, Tommy, in ballpark terms, could you remind me how many locations you guys have that are suitable for orientation or pad drilling orientation, and that being north to south?

Thomas Nusz

I don’t have that off the top of my head. Brett or Taylor may have that.

Taylor Reid

Yeah. In total, I think it’s over half. I don’t know the exact number, somewhere between 50 to 60%.

Thomas Nusz

We had 246 operated drill blocks that we talked about in the IPO. We’ve got 472 total. And probably with the Hebron deal at the end of the year, we’re probably more like 270, plus or minus, total operated drill blocks, if you were to back-date it. And so, half of those.

Taylor Reid

About half. One thing I would add is that while most of them are north, south, we do have some that are east, west, just because of surface configuration where we’re along the river or something similar to that.

Derrick Whitfield

Okay, that’s very helpful. Then, one last question, if I could, guys. Any updates on the Wilson Moore Three Forks wells?

Taylor Reid

The Wilson well is currently fracing, currently completing that well. So hopefully, we’ll have some results here this quarter. The Moore well should be fraced likely in June timeframe.

Derrick Whitfield

Perfect. That’s all from me, guys.

Thomas Nusz

Thanks.

Operator

Your next question is from Ron Mills. Please be sure your computer speakers are muted prior to asking your question.

Don Crist

Hi, guys. Actually this is Don Crist. Taylor, can you give us an update on Montana? And with the rig running out there continuously for a while now, can you give us any well results or anything you’re seeing differently from the North Dakota side to the Montana side?

Taylor Reid

Results that we’ve seen so far are in line with what we’ve seen in the North Dakota side. The wells that – early wells that were 23 stage frac wells within the 400 to 700 type curve band that we put out. We have early results on 28 stage frac, which looks very encouraging, but everything continues to be within that type curve band that we put out.

Don Crist

Okay. And you talked about potentially going eight, nine rigs by year-end and maybe 12 at some point in 2012. Can you talk about the timing going into 2012 of how you think you’re going to add those? Are they going to be one every quarter or is it going to be faster or slower than that? Obviously, it’s dependent on frac availability.

Taylor Reid

Yeah, it’s probably not a bad way to model it, would be one a quarter.

Don Crist

Okay. And just two smaller ones from me, for Michael. Can you talk about the differential more, add a little bit of color around it in Q2 and how we should model that? Is it still going to be 13% give or take or is it going to come down significantly?

Michael Lou

Yeah, so what we’ve been saying, Don, is 12% to 15% is a pretty good number for the next little while here before the big pipe comes on in 2013. Now, that being said, so first quarter is 13% range, fourth quarter of last year was in 14%, so in that range. The differentials at Clearbrook and Guernsey have been extremely positive. So it’s hard to tell exactly where the quarter will come out, but at least for the first couple of months it will probably be more in a call it a 6% to 10% range as opposed to the 12% to 15%. Now, we do think this is kind of a shorter term deal and we’ll end up going back towards the 12% to 15%. Tommy also mentioned some oil gathering that will help reduce that differential by a dollar or two when that oil infrastructure comes on first quarter of next year or maybe fourth quarter of this year.

Don Crist

Okay. And from an LOE standpoint, obviously it’s going to be dependent on timing but how should we model quarter to quarter on LOE going forward throughout this year? Should there be just a large drop-off in Q4 or will it be gradual throughout the second, third quarters as well?

Michael Lou

Yes, it will be pretty gradual, Don. The newer Bakken production comes on at around $5 to $6, especially when the salt water disposal system’s in, probably toward the lower end of that and so we’ll continue to blend downwards towards that $5 to $7 for the rest of the year, not totally unexpected that we’re kind of at this level, given for the first quarter, given the harsh winter and had some additional work because of that. But we always thought the first quarter was going to be higher and it would be working down throughout the year.

Don Crist

Okay. And just to confirm, you think the EURs could increase 20% to 30%, going to 36 stages from the 28%? Did I hear that right?

Taylor Reid

Based on what we’re seeing so far, we’re thinking 20% to 30%.

Don Crist

Okay. All right. That’s all from me. Thanks, guys.

Thomas Nusz

Thanks, Don.

Operator

Your next question is from Irene Haas. Please make sure your computer speakers are muted prior to asking your question.

Irene Haas

Hello. Can you hear me?

Michael Lou

Hello, Irene. Yeah we got you.

Irene Haas

Good to hear that you guys got the gas gathering operation going on. Just want to have a little confirmation. How should we look at the differential I mean, thus far, historically you guys earn a really nice premium to Henry Hub so with the new contracts as such getting in place, would that be sort of smaller than what you have been experiencing historically but still better I just want to have a little more granularity to that particular piece of the guidance?

Michael Lou

Sure, Irene. We’ve consistently said because of the liquids content here that we’ll be above Henry Hub. We’ll kind of have to watch how it comes in. I know that we’re pretty substantially above where Henry Hub is this quarter, but we’ll continue to watch it as it actually comes online and how that plays out. But right now, we think kind of modeling a little bit above Henry Hub is probably the right place to go.

Irene Haas

So are we talking about 120% or 150% over Henry Hub or more?

Michael Lou

10 to 15% is probably a good starting point.

Irene Haas

Okay, great. Thank you.

Operator

Your next question is from Jason Wrangler.

Jason Wrangler

Good morning, guys.

Thomas Nusz

Good morning, Jason.

Jason Wrangler

Just curious, as you look at the rig program, you have the six in the West, the one in the East. Is that the plan with those seven for the rest of this year and if as you add the eighth and ninth would you look at adding any to the East or would you be primarily going and developing in the West?

Thomas Nusz

Yeah, I think the way the guys have got it scheduled out right now as you go to eight and nine, we would likely add a rig in Montana in Hebron and then the ninth one would be over on the East side. So we would be two East and seven West.

Jason Wrangler

Okay. And just this is just kind of more curious than anything. How much longer does it take you to get the frac crew over to the east from the west? Does that take you actually a day or two, just curious on how the schematics of that works?

Michael Lou

No, that’s pretty quick move. Once you’ve got a rig down and truck over, it’s not a real long move for them.

Jason Wrangler

Perfect. Thanks guys. I’ll turn it back.

Thomas Nusz

All right, Jason, thanks.

Operator

Your next question is from Gail Nicholson.

Gail Nicholson

Hi, guys. How are you?

Michael Lou

Great.

Gail Nicholson

Just a couple quick questions. Going to the 36 frac stages, do you expect your Indian Hills wells to be a little higher than what you’re modeling for EURs right now?

Taylor Reid

They’ll be higher than the 28 stage model that we’ve been using, and like we said, 20 to 30%, going from 28 to 36.

Gail Nicholson

Okay. Because right now, you said that they’re mid to high on that 4 to 7 range. So we can assume it could be a little bit higher than 7 then, perhaps.

Taylor Reid

Correct.

Gail Nicholson

Okay. And then, with the excess potential tests that you’re going to be drilling this year, do you know when you should have results on those?

Thomas Nusz

Yeah. The first one that we’ve got is that one in Mondac. So it’s probably – we just spud the thing, so that’s probably third quarter.

Taylor Reid

Third quarter; correct.

Thomas Nusz

And then those other – we have another one on the southern end and one in Target, but that’s probably end of the year.

Taylor Reid

End of the year.

Gail Nicholson

And those will all be completed using 36 frac stages?

Thomas Nusz

Correct.

Gail Nicholson

Okay, great. Thank you.

Thomas Nusz

You bet.

Operator

Your next question is from Marty Beskow.

Martin Beskow

Good morning, guys.

Thomas Nusz

Good morning.

Martin Beskow

You had mentioned that it looks as if though you might be able to get a third fracing crew earlier than previously expected. What’s really kind of changing as to moving that up?

Thomas Nusz

You know, I think it’s just we kind of touched on it earlier; it’s just evolution of the discussions and availability. Continue to see more people move equipment into the basin now, equipment is one part of that equation and the other part is people. But I think it’s just how far advanced the discussions are.

Martin Beskow

And I guess with your discussions with the service providers, where are they seeing most of the hang up right now, is it on the crew side or on the equipment side?

Thomas Nusz

Taylor may be able to add a little more color to it, but I think it’s a little bit of both, really. You know, to split that out, I’d – it’s hard to say. Unless Taylor you’ve got any other…

Taylor Reid

Yeah, some of both, for sure.

Martin Beskow

Okay, all right. Well, thank you. Most of my other questions have been answered.

Taylor Reid

Well, Marty, thanks.

Operator

Your next question is from Peter Mahon.

Peter Mahon

Yeah, good morning, guys. Just had one follow-up question, you guys gave a full year production guidance range of 11,000 to 12,500 Boe per day. Where’s your comfort level with the bottom end of that range, with respect to adding that third frac crew, I mean, is adding that third frac crew give you comfort in the bottom point of that range or does that migrate you higher towards maybe the mid or high point of that guidance range?

Michael Lou

Yeah, so what we’ve said on the guidance ranges is that the second quarter we’re going to be towards the low end, around the low end of the range, but we haven’t changed our year guidance and we’ll be within that range.

Peter Mahon

Okay. So adding the third frac crew is not critical to hitting that range?

Thomas Nusz

Not – yeah, what I would say is, is that if we don’t get that frac crew, then it’s going to obviously just by virtue of timing and being at the low end, around the low end of the range for the first two quarters, it’s going to pressure us to the lower end. Getting a third frac crew obviously helps us get back on track. But again, if you’re – every day that goes by, it’s harder to catch up. So to really push to the high end on annual average, when you’re around the low end on the first two quarters gets more difficult by the day.

Peter Mahon

Okay. Perfect. Well, thanks a lot, guys.

Thomas Nusz

You bet.

Operator

Your next question comes from the line of Michael Hall.

Michael Hall

Thanks for the follow-up. Just a couple of things I was curious on. The backlog you currently have, how many of those are 36 stage completions, plan to be 36 stage completions?

Taylor Reid

Yeah. Most of them right now are 28 stage fracs. We have some 36 stage in there. We really transitioned more recently to 36 stage wells.

Michael Hall

Okay. So fair to say majority of them are 28 stage?

Taylor Reid

Yes.

Michael Hall

Okay. And then I guess kind of following up on a couple of the prior questions, on the question about kind of rig to frac crew ratio, is that partly a function or going to be a function of you’re not quite on pads yet and you’ll be limited to the extent that you need to transition from site to site and slows down the frac crew in that sense? Is that kind of the key variable there?

Thomas Nusz

Yeah, that’s part of it. Two things really. One is kind of sticking to plug and perf completions. Like I say, we’ve done a few where we’ve used – I don’t know, Taylor – 5 to 10 sleeve stages out in the toe, and we’ll monitor those. So part of it’s just continuing to base our plan on 36 plug and perf stages. Clearly, as you start getting into full-scale pad drilling, we’re going to be a lot more efficient. But for us, that doesn’t really start happening until 2013.

Michael Hall

Sure.

Thomas Nusz

Because we’re through the first half of 2013, we’re doing one well per 1280 to capture our blocks. In some instances, as Taylor mentioned, maybe half of those are where we do north, south or adjacent that gives us some efficiency.

Michael Hall

Yeah. And I guess I was also just curious from a full basin standpoint, if others start shifting towards pads and as that starts happening more and more throughout the basin, perhaps frac crews will become more available as people can run fewer fleets per rig.

Thomas Nusz

That would stand to reason. But keep in mind that rig count is going up at the same time.

Michael Hall

Sure, okay. And then, I guess just one other. Crews, did you see a lot of turnover with the kind of nasty winter that was experienced up there? You think you’ve gotten – or were you able to hold on to the crews that you had on your existing rigs and fleets?

Thomas Nusz

We did see some of that, Taylor do you want to...

Taylor Reid

Yeah, definitely saw some turnover, probably more on the frac crew side, rigs tended to hold them a little better but that definitely happened early on in the winter.

Michael Hall

Okay. Appreciate the extra color, guys. Thanks.

Thomas Nusz

You bet.

Operator

Your next question comes from Chitra Sundaram.

Chitra Sundaram

Yeah. I’ve remained confused a little bit about how we get from the 450 million to 520, 530, the 450 I appreciate with seven rigs, 53 net wells and 28 stage. And I wondered if you could just briefly take us through when I add 36 stages and remain at seven rigs what is the increment?

Then obviously I’m increasing the number of rigs I think to nine, and 36, sort of what is the increment and then finally, where is inflation coming to play? Because the well cost for being something like maybe high 7 million, went to about 8.3, thereabouts, in the call for Q4 and then now it’s closer to nine. And it’s just not clear to me how much of that is reflecting from the stage differential and how much is just inflation coming to play?

Michael Lou

So couple of things. One, our current budget is 490 million, as a starting point, and I think what we were talking about before is that with the seven rig program and two frac crews and the cost inflation and moving to 36 stages, essentially our capital will stay flat for the year but obviously we’ll have completed less wells in that type of situation. Now, 7.5 million is what we’re saying on the 28 stage frac.

Now you’re moving – if you go to the middle of the 8.5 to 9 range, 8.75 for a 36 stage frac. Previously we were saying in that 8.3 range, so there’s your inflation on those wells. But you can go anywhere in that range of 8.5 to 9 for that.

If you use that kind of midpoint and with a third frac crew, you’ll get back to the 47 net operated wells being completed for the year. And that will kind of get you back to that $525 million with the additional wells that are going to 36 stages at that kind of midpoint level will get you to that $525 million number. And then, as you get the 550, the reason for that is if you add a couple of rigs, call it rigs eight and nine, depending on when you might add them, that could bring you up to the 550. Now, you’re not going to get much benefit on a production basis from that, because they’ll be added later in the year.

Chitra Sundaram

Yeah, yeah, yeah. The 490 includes a bunch of infrastructure spend. When you think about just drilling wells, it’s sort of closer to 450, it’s operated and non-operated.

Michael Lou

Sure. So the 441 was our drilling budget, drilling completion budget. So if you want to go off of that starting point, you can do the same math and show the increase into our budget. So if our budget increased 60 million, the drilling budget, it’s on the drilling budget side, right.

Chitra Sundaram

Yeah. So when we go to 2012, if we are at that point hopefully at about eight or nine rigs, and we have seen in the newer wells, the 20 to 30% increase EURs, it’s setting the stage for some – even if we again have weather things, which by that point is an anniversary, one would imagine there should be some pretty nice production growth coming out of 2012 for which you all are quite well hedged already. Am I correct?

Michael Lou

That’s correct. We’ll see a lot of the impact of this 36 stage program. Given that most of them will be in the second half of the year, we’ll see a lot of that impact in 2012 as well as our program in ‘12. You’ll see the impact there, as well.

Chitra Sundaram

Yeah. Okay, thank you. Congratulations.

Thomas Nusz

Thank you.

Operator

Your next question comes from Jack Aiden.

Thomas Nusz

Good morning, Jack.

Jack Aiden

Good morning, Tommy. Most of my questions were already answered, but if you move from plug and perf to sliding sleeve, what kind of savings – how much more a frac crew could do and why are you not moving to it sooner than later?

Taylor Reid

So, if you move from plug and perf to sliding sleeve, you can probably – so let’s talk about a 28 stage frac. For us, it’s probably seven to eight range plug and perf, five to seven days. Sliding sleeve, maybe you can get it done in three or four days. So you’re a little more efficient. But we remain with plug and perf from a well performance standpoint and for surety of placement of our frac. And we monitor results. We’ve done some sliding sleeves and we’ll monitor the results of those, but at this point, are committed to staying with a plug and perf and we’ll revisit that as we go.

Jack Aiden

How much savings you could accomplish if you would go to sliding sleeve?

Taylor Rei

Well, I don’t have an exact number for you, but it’s not…

Thomas Nusz

…part of the problem, Jack, is, is that when we started into this, we were using all sleeves. And based on the performance and recoveries per stage, we shifted the plug and perf and saw noticeable improvement and more stages in plug and perf.

And I understand a lot of people are starting to use sleeves and these more exotic arrangements on sleeves. But for us to – we are not really confident on reversing on what we’ve learned so far or doing it to save time and dilute our first stage recoveries. So that I think is it why we’re a bit hard-headed about it.

Jack Aiden

Okay. Thanks a lot.

Thomas Nusz

You bet, Jack.

Jack Aiden

Thanks.

Operator

Your next question is from David Snow.

David Snow

What is your thinking on ultimate spacing per 1280 and what are you going to do to explore that?

Thomas Nusz

Yeah, you know, the way we’ve got it scheduled out right now, David, is three Middle Bakken wells and three Three Forks wells, focus more on the Middle Bakken right now just because we’ve got a lot more data on it than we do on the Three Forks. But keep in mind, with three – based on our calculations, three Middle Bakken wells per 1280, we think we’re getting 12 to 15% recovery of original oil in place. So that’s a relatively low number.

As we look at some of the data, the Brigham guys have talked about it a good bit, they’ve got three wells in that Olson unit. I think two of the three of those are effectively spaced on four wells per 1280.

And so, I think the three may be a bit conservative. We’re probably going to end up being more like four. But we’re going to watch what other people are doing. We don’t have any current plans internally to test that. But certainly enough industry activity out there, especially if you start looking at Whiting Sanish for us to get some good data on that and to be able to plan our 1280 full-scale development optimally once we get to that in end of 2012, into 2013.

David Snow

What is the spacing at Whiting Sanish?

Thomas Nusz

They’ve got a lot of wells that have been second well per 1280, probably 18 plus months of production there. Now they’re going to the third in a 1280 or three wells per. Keep in mind, rock quality there is a little bit higher, which is why you have higher recoveries than some of the other parts of the basin, at least, based on the completion techniques that they’re using right now. We’re starting – some of the other parts of the basin, we’re starting to catch up on recoveries because we’re using higher stages.

David Snow

Yeah. And when are you going to really start to hit your full manufacturing efficiencies? That will come after ‘12 when you start to?

Thomas Nusz

Yeah. That’s probably into the first half of 2013.

David Snow

Okay. And it will kind of take place over a couple years starting then or will it hit all at once?

Thomas Nusz

You know, probably as you look at – as we go into probably 2014, I would suspect that a large percentage of our activity will be on pad drilling.

Taylor Reid

We’ll pick up efficiencies as we go. We’ll continue to improve the process. Like Tommy said, full scale development’s going to be ‘13, ‘14.

Thomas Nusz

‘13 is kind of a transition year where we capture all of our drill blocks and start to transition to full pad development.

David Snow

Great. Well, thank you very much.

Thomas Nusz

You bet. Thank you.

Operator

There are no further questions at this time.

Thomas Nusz

Great. Well, thanks again for everybody’s participation in the call today. I appreciate all the hard work from the employees at Oasis. Appreciate the support that we’ve got from our strong shareholder base. We’ll be on the road quite a bit over the next few months and look forward to catching up with many of you along the way. Thank you.

Operator

This does conclude today’s conference call. You may all disconnect.

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