Seeking Alpha
We cover over 5K calls/quarter
Profile| Send Message| ()  

Executives

Michael Lou – Chief Financial Officer

Thomas Nusz – President and CEO

Taylor Reid – Chief Operating Officer

Analysts

Ron Mills – Johnson Rice & Company

Marty Beskow – Northland Capital Markets

Marcus Talbert – Canaccord

William Butler – Stephens

Dave Kistler – Simmons & Company

Andrew Coleman – Raymond James

Jason Wrangler – SunTrust Robinson Humphrey

Scott Hanold – RBC

David Snow – Juniper Research

Peter Mahon – Dougherty & Company

David Deckelbaum – KeyBanc Capital Markets Inc.

Oasis Petroleum Inc. (OAS) Q3 2011 Earnings Conference Call November 8, 2011 11:00 AM ET

Operator

Good morning, my name is Robin [ph] and I will be your conference operator today. At this time, I would like to welcome everyone to the Third Quarter 2011 Earnings Release and Operations Update for Oasis Petroleum. All lines have been placed on mute to prevent any background noise. (Operator instructions).

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

Michael Lou

Thank you, Robin [ph], good morning everyone, this is Michael Lou. We are reporting our third quarter ending September 30, 2011 results today, and we’re delighted to have you on our call. I’m joined today by Tommy Nusz and Taylor Reid, as well as other member of the team.

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 the 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 & 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 third quarter 10-Q tomorrow. During this conference call, we will also make references to adjusted EBITDA which is a non-GAAP financial measure. Reconciliations to adjusted EBITDA to the applicable GAAP measures can be found in our earnings release or on our website.

I will now turn the call over to Tommy.

Thomas Nusz

Good morning and thank you for joining us this morning to discuss our third quarter financial results, recent operational activity and our outlook for the rest of the year. I’ll begin with an operational update outlook and then I’ll turn it back over to Michael to cover financial highlights.

We had a great quarter coming out the heels of two tough quarters that were largely influenced by weather. The 47% production increase quarter-over-quarter is a good indication that operations are getting back up to speed. As we announced in late October, we continue to grow production and our operational reports have us around 14,300 BOE per day for the full month of October.

Included in that most recent production, growth is about two million cubic feet per day of net incremental natural gas production above the 3Q average of 2.45 million cubic feet per day which we attribute to new wells being connected to our gas infrastructure that we’ll discuss more in a moment.

The team did a great job ramping up production in the third quarter to get us back on track operationally.

Although we have the obvious weather related issues in the first half of the year, we have made some important strides this year in setting up our asset base for the most optimal cost efficient development going forward. We have significantly de-risked our acreage position proven the impact of 36 stage completions and have begun understanding in the full potential of the Three Forks formation.

We’ve added two additional rigs in October takings us to nine operated rigs and we are ramping up our activity as planned going into 2012. So we believe 2012 will be an even better year because of the actions that we’ve taken during the course of this year.

We continue to make progress delineating and securing our acreage position as well as consolidating in our core blocks. Counting our core de-risked acreage, which across the basin is about 250,000 to 260,000 net acres, we have an inventory of about 1,500 remaining operated locations and 2,400 total gross locations.

On our nine rig program, that equates to about 17 years of inventory. As we ramp up to 10 to 12 rigs depending on the efficiency and market conditions, we would envision being able to do about 120 gross operated wells per year. So at the end of 2012, we’ll have about 1,400 remaining locations and approximately 12 years of inventory.

Remember, when we talked about our inventory in our de-risked acreage, this is the acreage that’s in the heart of the play and excludes any fringy stuff. All of the sub service mapping indicates that these 250,000 to 260,000 net acres look to be within our tight curve ranges.

Our team continues to upgrade our land position increasing acreage in our core de-risked operated areas and dropping acres in geologically challenged areas. We continue to focus on increasing our working interest in our operative blocks so that each gross operated well that we bring on to production has more of an impact on our overall net production.

Additionally, we estimate that this year’s drilling program, we currently have approximately 160,000 net acres held by production. So a little bit ahead of where we expected to be coming into the year and a function of the great job our land group has done consolidated acres in our core drill blocks.

As you know, we now have nine operated rigs in the basin. We have also secured the contracts that will allow us to go to 12 rigs by the end of 2012 and potentially as early as August. At the same time, we’ve managed our rig contracts so that we have the flexibility to scale back to five to six rigs in a soft oil price environment.

We also have three frac crews now but the third crew started in late June. All three of our crews were running efficiently in September and all are dedicated only to us. At the end of September, we had 21 wells waiting on completion which is down from 23 at the end of June.

We brought 22 middle Bakken and Three Forks wells on production in the third quarter with an average working interest of 79 percent, 9 of those were brought in September.

That brings our total operated wells brought in production this year to 46. But these wells and the new wells we expect to bring on production in the fourth quarter, we believe that we will be around the low-end of our 2011 production range as we noted in late October.

At the end of September, we have four wells that have been fracked but we’re waiting on clean out. This count grew to nine in October as we slowed clean out activity. So our total wells waiting on completion increased from 21 to 26 in October, but we also added a third work over rate of focus on clean out some work through our backlog.

As I mentioned earlier, we had about 14,300 BOEs per day of production on October, so we were still able to grow production considerably above our Q3 average. I’ll now switch gears a bit and give you an update on our infrastructure development. On the gas side as of November 1st we connected 31 operated Bakken wells to gas gathering lines.

A total of 29 of those were connected in the third quarter, 13 in South Cottonwood on the East side of the basin, and 16 of those on the West Williston side of the basin and Red Bank in Indian Hills.

As a result and the new wells coming on line, daily gas production has increased almost 2 million cubic feet per day in October. We are anticipating an additional 70 to 75 wells to be connected to gas gathering infrastructure by the end of the year.

So we expect to have connected approximately 100 wells in 2011. In the first half of 2012, we expect to connect and additional 40 wells including wells from North Cottonwood. This production all falls to the bottom line as there’s minimal incremental capital cost associated with this incremental production.

We’ve always forecasted pricing on the gas side approximately 110 to 115 percent Henry Hub. Given the percent of proceeds contracts coupled with the high geo content of the gas, this may prove to be a little bit conservative. And something along the lines of 150 percent of Henry Hub might be a bit more accurate for modeling purposes.

Additionally, the construction of the oil gathering infrastructure continues to make progress and we continue to expect wells to be connected at the end of this year and early in 2012.

So far two wells have been physically connected to the system, but have not yet made first delivery. We are anticipating connecting approximately 75 gross operated wells in Red Bank Indian Hills and Hebron to the gathering system. Substantially, all of the new wells completed in these areas will be connected to that system.

The system will help us eliminate trucking cost of approximately $4 per barrel which will immediately impact our realized prices and will keep oil flowing through tough winter conditions.

So these trucks will no longer be required to pick up the oil. There is a fee associated with the production which will show up as a new line item in our financial statements. So net-net we expect to improve our margins by approximately $1 to $2 a barrel.

In addition with the gathering system in place, we will have the flexibility to nominate our oil to different delivery points along the system. We have taken steps to transfer some of the marketing responsibility in-house to take advantage of this opportunity.

The salt water disposal system, we are investing in this year and next, will also be extremely valuable to overall operations. In the third quarter our LOE was impacted by the cost to transport and disposal of water.

On a per BOE basis, salt water handling was about 28 percent of our cost in the first half of the year, and in Q3 salt water handling was about 48 percent of our cost. This is due primarily to increased waiting times by the trucks at SWD wells and to a lesser extent increase cost per hour charged by trucking companies.

We had this in mind when we increased our SWD budget in August to bring forward some of the 2012 capital and offset these costs. While not reflected in the third quarter numbers, we are already seeing a positive impact of our SWD system in the fourth quarter.

The SWD system in the Southern part of the East Nesson is currently operational and Oasis expects the SWD system in West Williston to begin operations in the first quarter of 2012 with more wells being connected throughout the year.

This will eliminate the need for trucks, simplify logistics, and reduce cost in 2012 by $2 to $3 per BOE from current levels. Now let’s turn to well performance of our 36 stage completions in the Three Forks as well that we have on production. As you know based on our findings we have transitioned all future wells to 36 days completions.

We are encouraged by the results and see an approximate 20% to 30% increase in production compared to nearby wells completed with 28 stages. This supports the thesis that an increase in stages continues to increase production and is a very efficient use of our capital.

We continue to be encouraged by what we’re seeing out of Three Forks at this stage of testing while the geology is a bit different than in Bakken, we have some positive test results. We’ve now completed and brought online four wells in the Three Forks.

We have not yet discussed the results of our Spratly well which was completed with 36 stages in South Cottonwood. The Spratly well produced 61.1 thousand barrels of oil over the last 47 days or an average daily production of 1,300 barrels of oil per day.

This clearly is a good well and we’re in the process of drilling another well in the middle part of North Cottonwood to give us more Three Forks test on each side of our position. We also have another Three Forks well in Indian Hills that’s waiting on completion which will be closed to the high stead well that we’ve talked about previously.

As we find 10 geo scaling [ph], we believe wells in this area will produce inside the range especially as we increase to 36 stages. As we continue to test the formation, the data we gather should further demonstrate the evolution and the upside of the play.

Finally, as we continue to push the boundaries on our acreage, we’re looking forward to getting production data on our wells in our target the Mondak areas. The capital well in Montana will provide a good data in our target area as a western extension of what we’ve been seeing in Red Bank on the North Dakota side. Further to the south in our West Williston position, the Bay Creek barrel well is a significant step to the south in our Mondak area.

It is still early days for this 28 stage well but the well appears to be around the low end of our tight curve range. We expect to get more data over the next few quarters on Mondak as we will drill and complete three more wells here. One well on the Northern Mondak is waiting on completion and another well in Central Mondak is drilling. The other well should be an offset to the Bay Creek Federal.

With respect to well cost, we’re maintaining our estimate of approximately 8.5 million for an all sand well and approximately 9.2 and 9.4 for a well with a ceramic and sand mix based on our 36 stage plug-in per completions. With service cost escalation, learning in the Three Forks and whether on the first half of the year, we did see our overall average ceramic sand accommodation wells more on the $9.6 to $9.8 million range. Going forward well cost look to becoming back more into our $9.2 to $9.4 million range.

All that being said, we continually look for ways to reduce overall well cost and that will help us we get closer to back half of 2012 and even more so in 2013 as we start to get into more full-scale mode. With that, we expect to reduce well cost by at least 10%.

We are currently working on well configurations on our multi-well development pads to determine the optimum efficiency for well production and spacing. We will be testing four Bakken wells first spacing unit and six total wells including Middle Bakken and Three Forks per spacing unit early next year.

Additionally, we have been testing the impact of using 100% sand in the northern portions of Red Bank and North Cottonwood. We have chosen these areas primarily due to shower debts and lower pressures. Our original assumption was in this environment we would not compromise well performance by using all sand. Results today confirmed with relief that the wells would perform in line with wells with ceramic and sand mix. We are saving $500,000 to $750,000 on these 100% sand wells.

Lastly, we continue to expect our in-house frac crew to save us approximately 16 to 20 million in CapEx on an annualized basis. We currently expect equipment to show up around the end of the year and the new crew will begin completing stages in the first half of 2012. It’s probably safe to assume that we will save about 10 to 12 million in the calendar year 2012 with OWS.

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

Michael Lou

Thanks, Tommy. Before I get into the financials, I’d like to first talk to you about our recent high-yield debt issuance. As we’ve discussed before to fund our growth profile, we were always intending to opportunistically tap at debt markets. A window opened in the high yield markets and we prudently launched our deal to lock-in record low rates.

By taking funding risk off the table, we now expect to be able to fund our capital budget out spend given an $80 per barrel WTI oil price environment into the middle of 2013 without tapping our revolver. Including our revolver which was recently increased to $350 million of burrow and base capacity, we will have about a billion dollars of liquidity when the 6.5% notes close on November 10th.

As Tommy mentioned, we had a record third quarter with adjusted EBITDA of 62.9 million on revenues up $88 million fueled by nearly 50% quarter-over-quarter production growth. Differentials remain strong in the third quarter as we average a 6.3% differential to WTI.

Pricing at Clearbrook and Guernsey, our primary delivery points were at a premium to WTI during the quarter. On another note, as you know, we also used hedging to protect our drilling program. We continue to layer in hedges opportunistically as the market warrants. We now have 8,500 barrels per day hedged for the remainder of the year, 13,500 barrels per day hedged in 2012 and 7,000 barrels per day hedged in 2013.

Even with future oil price volatility similar to what we experienced in the third quarter, we feel comfortable that our drilling program is well protected based on our attractive floor prices which average around $85 to $90 per barrel of WTI. On the cost side, Tommy discussed the impact of LOE cost and how SWD infrastructure will help alleviate these cost pressures in the future.

DNA cost have trended a bit higher as we continue to grow our teams to support a 12 rig program but are still in line on the dollar per BOE basis. Production taxes have also been a bit better than originally predicted. Our capital expenditures in the third quarter were $206 million and $414 million year-to-date out of our $627 million budget for the year.

In conclusion, we had a great quarter and we have the right team in place to execute the increased drilling and completion activity. The team delivered production growth, all the while implementing measures to reduce well costs, LOE and other costs as Tommy described. We also have logged in the cash and Cash Flow to keep extremely financially flexible in any type of commodity to price environment and we have matched that with our service contract flexibility.

We’re looking forward to a strong fourth quarter and setting the stage for additional growth in 2012. With that we’ll turn the call over to Rob and to open the lines up for questions.

Question-and-Answer Session

Operator

(Operator instructions). And your first question comes from the line of Ron Mills.

Ron Mills – Johnson Rice & Company

Good morning. Tom a question, you’re starting to test more than Three Forks. Any comments as to what kind of – has been saying about multiple binges in the Three Forks or are your tests going to allow you to test multiple binges or even see – are you taking core as far enough or deep enough to determine the prospectively of that to augment just the binge or the Three Forks?

Thomas Nusz

Ron, we haven’t done any work on that. So far there are a few wells across the basin where we’ve taken cores before but I don’t think that we’re in a position, at this point, to augment anything else that’s been said about the other binges and the Three Forks across the basin.

We’ll continue to watch what’s going on there but I don’t think that we have anything to add to that.

Ron Mills – Johnson Rice & Company

Okay and from an activity standpoint, it sounds like you’ve – you’re already at nine rigs but you’re maybe reading into this but you’re already talking to people about access to rigs to go to 10 to 12 by the end of next year and on the completion side, you obviously have the capacity with the three current crews plus your own for express but how about the infrastructure that is going in both East and West in terms of its capacity to handle that kind of ramp to 12 rigs or are there more discussions about potential expansions there?

Thomas Nusz

I think we’re in good shape. Taylor, you may want to provide a little more cover on that.

Taylor Reid

Yes, so the infrastructures were going 12 rigs. The base infrastructure will be in place by the end of this year will add to it in some of the areas from North Cottonwood for example, we’re expanding the gas gathering and processing so that area will be covered next year and essentially it’ll just be expanding the gathering systems to pick up the new wells as we drill them in each area.

But we should be in good shape with respect to infrastructure.

Michael Lou

Yeah, most of the big pipe will be in especially as the North Cottonwood project gets done so then it’s just little pipe to get to the well sites.

Ron Mills – Johnson Rice & Company

Okay and then lastly, just from Michael, maybe for you directionally. You talked about the financing getting you through kind of mid 2013 on your planned activity levels. Is that assuming you get to kind of a 12 rig run rate by the end of next year and that’s where you’re holding it flat in 2013 as we just look for directional – we know the direction but magnitude of CapEx increases?

Michael Lou

Yeah, that’s right Ron. We’ll obviously come out with a little bit more detail when we set capital budget for 2012 later this year but as we move towards that 12 rig program next year, that’s assuming that we go in that direction as well as keeping that 12 rig program flat going forward.

Ron Mills – Johnson Rice & Company

Okay, great. I’ll jump back into you. Thank you guys.

Operator

And your next question comes from the line of Marty Beskow.

Marty Beskow – Northland Capital Markets

Good morning. Based on recent well results, could you update us on your E-wires [ph] as to kind of what you’re seeing and how that relates to the tight curves estimates that you’ve given so far for East Neston and also West Neston?

Michael Lou

Yes so East Neston, as you know, on 28 stages we were estimating 350 to 600. On the West side, 400 to 700 and what we’re seeing based on early data is a 20% to 30% uplift with 36 stages. Now, in some of the more prolific areas say South Cottonwood, Indian Hills, some of the wells – some of the performance is a bit above the 30% and some of the lower productive areas, the Northern part of Red Bank, North Cottonwood, we would expect it to be more in the 20%, maybe a bit less than that.

With all those numbers, you should be able to get a pretty good sense for what the new ranges will be. At some point here in the not so distant future, we’ll be able to make that switch to where it’ll be a lot cleaner for everybody.

Marty Beskow – Northland Capital Markets

And how about as far as for the Three Forks wells, what are you expecting so far from those?

Thomas Nusz

At this point, it’s a little bit early to tell. Obviously, we don’t have a whole lot of internal data points but we’ve got some external data. But what we’ve said consistently is, is that it is going to be a bit different so it may be, call it 20% less than the Middle Bakken.

With that being said, when you look at wells like the Spratly well, it looks pretty consistent with the Middle Bakken. It’s going to be a bit variable and we just need to get more data. If they’re all within the tight curve vans but we need more data.

Now, we’ve obviously talked about the two wells on the west side of the base and the straddle state line over in Hebron that are the low end or below the low end of our tight curve bands for 28 stages but those two wells, one of them effectively had 23 stages. The other one, effectively, 18 to 20 stages but per stage recoveries looked real good, they just didn’t have enough stages.

Marty Beskow – Northland Capital Markets

And how about for your plan for drilling in 2012 of the gross number of wells, what percent of those do you plan on having drilling and how many of those will be individual wells that will be holding on 1280 per unit.

Taylor Reid

It’s probably – I don’t know if we’ve got a number for that, it’s probably a fairly low percentage. It’s probably 10 percent, maybe 15 that will be pad wells for the calendar year.

Michael Lou

So at least half of the program they’re still drilling the hold acreage. And full pad wells where we’re drilling out of a full in-fill patterns is a small subset under 10 percent, but we will be drilling a number of just wells that have one – going south like we have been.

That total off of pads maybe 30 to 40 percent. I don’t have the immediate number in that range.

Thomas Nusz

Okay, so that would include full pad development as we call it, wells and then the smaller pad where we’re heading to 1280s with one small pad, but only get in one well in each 1280.

Marty Beskow – Northland Capital Markets

And you said that you were going to test up to four Bakken wells per 1280 acreage reduction is that correct?

Thomas Nusz

Correct.

Marty Beskow – Northland Capital Markets

And up to six loads for the spacing units, so is that to assume that the other two are going to be in the three Forks?

Thomas Nusz

Yes, I think the way Brett got that laid out is that – in that particular pilot, 1280 acre pilot, it would be three on three.

Marty Beskow – Northland Capital Markets

All right. Thank you.

Thomas Nusz

Okay.

Operator

Your next question comes from the line of Marcus Talbert.

Marcus Talbert – Canaccord

Hi guys, good morning.

Thomas Nusz

Good morning.

Marcus Talbert – Canaccord

Hey Tommy, you briefly touched on your inventory during the opening comments here, and you mentioned the 10 to 12 rigs would imply I think approximately 120 gross operated wells next year, thinking about some of the pad drilling effort that Taylor just mentioned and some of these drilling efficiency that you guys have picked up throughout the year, does that number – is there a buffer in that number for weather delays or any external factors?

It just seems a little conservative I guess.

Thomas Nusz

Yes, it is. We have historically used 10 wells per rig per year, so with 12 rigs, you know, that would get you to 120, but given recent performance, you know, we’re generally Taylor’s rig release about 25 days, we’ve had some as low as 20 and then when you count rig moves, you know, it’s not inconceivable that you can get, if everything goes right in decent weather, that you can get 11 to 12 wells per rig per year, and then obviously that improves a bit with pad drilling as well.

But you’re not going to see much of that in 2012. So there could be – I mean the short answer is yes, it’s a conservative number, there may be more upside to that.

Taylor Reid

I mean on a single small pad where we went one well north and one well south, the best we’ve done so far rig release to spot of the next well was 12 hours. So you start doing a lot of that and then that number could grow.

Marcus Talbert – Canaccord

Right.

Thomas Nusz

Yes, this year’s average, 2011 aggregate average is 10.8 wells per rig per year.

Marcus Talbert – Canaccord

Okay, great.

Thomas Nusz

A bit above the conservative 10 that we’ve been using.

Taylor Reid

Just to be clear, when we said 120 wells per year, that was when you get to a full 12 rigs. Next year we’ll have – we’ll be growing into the 12-rig program so you’ll have an average of around 10 and a half rigs running throughout the year.

So that 120 number for next year is actually maybe a little bit lower than that.

Marcus Talbert – Canaccord

Right. Okay. Thanks for the color there guys, and you touched on the progression within three Forks, I guess – in terms of your Bakken well results, as you move north into the Red Bank, it looks like they’ve been – sort of variable there.

Do you know, I guess how many of these producers have been completed with more than 30 stages out of the program that you’ve laid out for this year?

Thomas Nusz

Thirty-six stage wells recognized so far this year?

Marcus Talbert – Canaccord

Yeah.

Taylor Reid

Hold on, let me get that. It’s in this sheet. Thirty-six stages sold.

Michael Lou

Yes, 11 wells that have been done with 36 stages, five of those have been on pump so far.

Marcus Talbert – Canaccord

Okay. And looking at some of the data for that Red Bank area, it looks like one of your strongest producers, I think it’s the Logan Well, is a little bit east of where much of the activity has been there.

Is there anything that you can tell from the interval as you move east to west? I understand that it shallows as you move north towards the right county. But thinking about the position as you move east of the heart of the activity, is there anything you’re seeing different?

Taylor Reid

Yes, just generally, in Red Bank to the east and to the southeast, the results were better. So, the Logan is a good example. Another good example is the Andrea well. There was also an area in there where there’s a little bit of a structure. So, water cuts tend to be a little lower in that area and we’re seeing better performance.

So as you trend to the west and more to the north and west, the water cuts tend to go up.

Michael Lou

Right because you’re getting shallower.

Marcus Talbert – Canaccord

Okay.

Michael Lou

And we see that pretty consistently as it start to shallow east or west that water cuts tend to go up.

Marcus Talbert – Canaccord

Okay. Super thanks. Thanks for the call, guys. I’ll get back in line here.

Michael Lou

Perfect. Thanks.

Operator

And the next question comes from the line of William Butler.

William Butler – Stephens

Good morning.

Michael Lou

Good morning.

William Butler – Stephens

Thinking about where your rigs could be added in 2012 on the nine rigs program, it’s two in the east, it looks like seven in the west, do you have any sense of where you’re going to focus those added rigs in 2012?

Michael Lou

So, we’re still working on the final plan. But we’ll add a second rig in Hebron, so we’re drilling in the Montana area. We’ll continue to run most likely two rigs on the east. We talk about the infields, we’re going to test some infield pilots where we’re drilling anywhere from Florida six wells back-to-back and we’ll have those pilots going on both in Indian Hills and in Red Bank.

So that will consume some of the rig time as well.

William Butler – Stephens

Okay.

Thomas Nusz

So we have 12 rigs running and there are probably eight to nine on the west side, three to four on the east just depending on how the program lays out.

William Butler – Stephens

Okay. And then have you got any commentary on sort of how the fractures in place on your western versus your eastern properties could impact spacing or the amount of three or four per section yet? I mean there was just not an update on that. Can you talk a little bit more about prospectively of three towards east versus west?

Thomas Nusz

Yes, on the east side and the south, especially if you anchor off of the Spratly well, it looks as good as the Middle Bakken wells. Now we’ll get a data point here in a not-so-distant future with the well that we’re drilling right in the middle of Cottonwood.

And then on the west side, we still need to get some more data. And we’ve got the high (inaudible), we’ve got the other well that is drilled but not yet completed that’s right next to it and then those two over on the state line. But again, those weren’t completed with the highest stages. So, we still need to get a bit more data.

But it’s probably fair to say that it is a bit more variable on the west side than on the east.

Taylor Reid

Yes, more variable. So I’d say at this point the most perspective, like Tommy talk about on the east side, is South Cottonwood. On the west side is Indian Hills. We’ve got the best data there as you go to Red Bank and Hebron.

We’ll run more tests. We’re encouraged by what we’ve seen so far. And then North Cottonwood back on the eastside, we’ve got some early wells that were drilled with short laterals 5,000 foot in an 8th stage frac so we need to continue to step, you know, longer laterals and more frac stages to the north which we’ll do.

William Butler – Stephens

Okay. And then one last question. Is there, you know, with the cashing and the balance sheet, are there any, you know, alternative uses you all could see, you know, between now or just using that for drilling between now in 2013. How should we think about, you know, that money?

Thomas Nusz

You know, the cash to be raised is primarily for our drilling program but obviously gives us some flexibility if we see good volt on acquisitions. We’ve been pretty clear on that too that, you know, if we find good positions instead of drilled blocks that we can operate. We’ll look at those opportunistically.

William Butler – Stephens

Okay. With that I have to come with production versus being – what acreage would that be?

Thomas Nusz

As a general rule and a lot of times, well, they may come with production. It’s primarily acreage just like the deals that we did at the end of last year, right? You know, there was, I think, out of those two deals we spent $80 million and as I recall we picked up 3 to 500 barrels a day something like that.

William Butler – Stephens

Okay. Is there a lot of ideal flows too going on?

Thomas Nusz

There is but it is starting to taper off a bit. I mean, at least for things of any size.

William Butler – Stephens

Okay. That does it for me. Thank you all.

Thomas Nusz

You bet.

Operator

And your next question comes from the line of Dave Kistler.

Thomas Nusz

Good morning, Dave.

Dave Kistler – Simmons & Company

Good morning, guys. Real quickly here. You guys did mention on the last call kind of a CapEx outlook for ’12 very, you know, kind of a wide swop at 750 to 800 million. And I know you can indicate if that’s change or bigger or higher but can you indicate what percentage of that has drilled at?

Michael Lou

Yes. Of our capital program, we were assuming around 700 million of drilling and completion capital there and then over, we’re saying on top of that, Dave, was that if you had about 20 million of lease expense which we kind of think of as our land load every year you add about 10 million for geologic work about $20 million for additional infrastructure and a little bit of OWS and you put some contingency dollars in there, that’s how you get to the $750 to $800 million number.

Dave Kistler – Simmons & Company

Perfect. That’s helpful. And then in thinking about that, I’m guessing you’re reflecting the benefits of OWS in the cost savings there, Tommy, you highlighted some of the potential well cost savings going forward. Is that factored into that number or we’re assuming that we’re not really moving to kind of a lower development well cost at that point.

Thomas Nusz

Yes. For next year, we’re not basing much of that in just because of the percentage of wells that are in full pad and when we talk about the 10% plus then that’s assuming that you’re getting in the full big pad development mode. About the small pads where we do one north, we do one south and like we’ve been doing for the last couple of years.

And so, really, I mean, it’s 2013 before you start doing that in any meaningful way. And Dave just so you know, I mean, those numbers are based off of some pretty high level numbers at this point.

We’re going to get to our full capital program obviously a little bit later this year when it’s approved by the board in December and we’ll come out with a little bit granularity. But what we’re assuming there was around 75 net wells and we’re just multiplying it by around at $9.2 million on average for the wells which gets you to your 700 million of drilling completion budget.

Dave Kistler – Simmons & Company

Perfect. That’s very helpful. And then just kind of thinking about when you brought in the new frac crew, it took a little bit time to get them up to learning curve and more efficient as you bring in a new frac spread, are you guys kind of factoring how that learning curve will take place or are there things that you digested and understood that you think you can drop drive the efficiency gains that prove faster?

And kind of color around learnings that took place and how you think about that for moving forward in kind of production forecast.

Thomas Nusz

I’ll let Taylor add a little bit of color to it, but keep in mind that the three frac crews that we’ve got running for us right now, all came from outside the basin. So we’ve – we’ve got a pretty good bit of data on this so far.

Taylor Reid

We think that – it’s going to take us a little bit of time to get the crew up and running efficiently and so we factor in as – we say by 2Q, we will be fracking our own wells doing it efficiently.

We think with first quarter or a very early 2Q that we’ll be starting some fracs and we’ll start out doing our operations and then ramp up to 24-hour operations to get more efficient. We’ve done – taken some of that same approach with some of the crews that have come in from outside the basin.

Dave Kistler – Simmons & Company

Great, that’s helpful. And then just last one, as you guys bring the marketing efforts in-house, can you talk a little bit about what that might represent in terms of cost savings? Or benefit to your realizations and then anything that you guys are doing to make sure that you have some work around on this LLS WTI spread?

Taylor Reid

I think bring the marketing in-house as we’ve talked about, you know, the early savings is really in the gathering system, and so eliminating trucking and being able to put – take our oil by pipe to delivery points. In fact, we’ll cut $1 to $2 of barrel. It’s going to be a net benefit to us of $1 to $2 of barrel.

And from a marketing standpoint, what we’ll then be able to do is sell the third-party further downstream rather than just that the well had. So it does increase our flexibility and allow us to get to more markets outside of places like Guernsey or Clearbrook.

So we think we’ll get some more attractive netbacks. But we’re still working through all that. David, just can’t tell you how much we’ll have. That’s not directly WTI-based but we will have some sold at other market. And there could be places other than LLS.

It could east coast, it could be west coast. Places that have better pricing.

Dave Kistler – Simmons & Company

Okay. That’s helpful. And also just on that though, isn’t there a fee that you’re paying your marketers or percentage spread that they take just off the top? That gets removed as well, I would imagine.

Taylor Reid

Yes. The third-party arrangement, generally, it’s just a deduct. So you don’t know what amount there is, but, yes, sure they’ve got some charge that they have to cover their work and their overhead so that would then go away.

Dave Kistler – Simmons & Company

Okay. That’s helpful, guys. I appreciate the honest answer there.

Taylor Reid

All right, Dave.

Operator

And your next question comes from the line of Andrew Coleman.

Andrew Coleman – Raymond James

Thank you very much.

I have a question, as you move to bring in on more of gas well, do you expect to see much for change in the oil waiting the company for 2012?

Thomas Nusz

No, it’s not a big enough number, really, to move the needle that much on overall oil waiting. We’re at 92% oil on a preliminarily [ph] basis right now. It may move by a point, but it’s not going to be meaningful.

Andrew Coleman – Raymond James

Okay. Great. That was good.

And then getting your comment on the water disposal system, you said it was 48% on cost in the third quarter, how much you think that could fall down to once you get all your disposal wells and pipes all set up?

Taylor Reid

Yes, Andrew. It’s closer to 25% in the first half. And I think that’s an initial bag that you get to and you’ll continue to move cost down from there with the salt water disposal system. But it should remove quite a bit of capital cost and a lot of the increases that we saw here in the different quarter.

Andrew Coleman – Raymond James

Okay. So you target back to 25% range in then?

Taylor Reid

Yes, 25% and then ultimately moving probably a little bit lower now.

Andrew Coleman – Raymond James

Okay. Thank you very much, a couple of easy questions.

Michael Lou

Yes, thanks.

Operator

And your next question comes from the line of Jason Wrangler.

Jason Wrangler – SunTrust Robinson Humphrey

Hey, good morning, guys.

Michael Lou

Good morning, Jason.

Jason Wrangler – SunTrust Robinson Humphrey

Just on the well completion, it looks like you’re getting a backlog down. What do you think in a perfect world would you have as far as a backlog would be in the 15 to 20 range? So is there a little bit still that you’re working off with the three crews now?

Thomas Nusz

Yes. So, I think historically, what we’ve been talking about is that it’s somewhere around 2012 when we’re running seven or eight rigs. So when you start running 12 rigs, that number is going to grow to 18, maybe 16 to 18, something like that.

Jason Wrangler – SunTrust Robinson Humphrey

Okay.

Thomas Nusz

And of course, we’ve talked a little bit about this before, but as our drilling gets more efficient, then we’re adding to the inventory a little bit faster than we thought as well.

Jason Wrangler – SunTrust Robinson Humphrey

Right. And then I guess on the infrastructure too, as you’re getting all this stuff put in, as we get to the year end, about how much is the production do you see will be going in the pipes as we get to year end when the weather starts getting really bad so that if we do have another bad winter, what we’re looking at as far as what we saw to be trucked?

Thomas Nusz

On the oil production side?

Jason Wrangler – SunTrust Robinson Humphrey

Yes.

Michael Lou

And so, on oil production going in the pipe at year end, we think that most of the wells will be hooked up by year end. We probably won’t be filling in to the pipe until first quarter, which partially has to do with nominating and surety of having the wells hooked up and be able to move that oil.

So we’ll have the system in place some moving prior to year end but expect most of that impact to come January in the first quarter.

Jason Wrangler – SunTrust Robinson Humphrey

Perfect. Thank you.

Operator

And your next question comes from the line of Scott Hanold. Scott, your line is open.

Scott Hanold – RBC

I’m sorry about that, had it on mute. You mentioned one of the rigs that you’re going to add is going to go over Hebron area. Is that because of you need to capture the acreage or you just want to, sort of, just take charge in the activity out there?

Thomas Nusz

That’s more associated with continuing to extend and test some of the acreage so for example we acquired lost position last year and that was about 10,000 acres in almost all that is held by production but with the second rig, we’ll go ahead and start to drill some of that acreage.

It’s a little south of where we’ve been drilling but we think in a good area so we’ll start drilling one Bakken well for a spacing unit within that area next year.

Taylor Reid

That’s all south of the river.

Thomas Nusz

All south of the river.

Scott Hanold – RBC

Okay and then up and target, when does that Northwestern extension well gets tested in and remind me again the least times that you have up there and how active in ’12 you can be in target.

Thomas Nusz

The well that’s drilled that it’s actually fracked is called a copper well and it will be tested probably this month but it’s just waiting to be cleaned out so here hopefully in the coming weeks we’ll begin to test that well. In 2012, we’ve got three additional wells that we will drill and target and those are – at lease expiration but we’ve got a program in place that will be able to hold all the leases there.

Scott Hanold – RBC

Okay and my mistake, was there another well that you had planned up in the far northwest corner, am I mistaken? That’s just an open end acreage Bakken here, I apologize.

Operator

And your next question comes from the line of David Snow.

David Snow – Juniper Research

Hi. There’ve been one or two, 7,000 barrels a day, wells – can you give us any ideas as to what’s going on there? They're not yours but.

Thomas Nusz

Yes so you’re referring to the widening well that was announced – I don’t know if you heard a few weeks ago there was a 7,000 barrel a day well in and it was to the southeast of our Indian Hills position. I guess directly to the east, maybe a little south of Indian Hills but in a good position and we don’t have any more data on that well other what was announced.

David Snow – Juniper Research

Is there a difference in the way they completed it or is it just the rocks?

Michael Lou

Hard to tell at this point. We are getting closer to the Atlantic [ph] line over there but I don’t know that we have enough data to tell us whether it’s rocks or completion.

David Snow – Juniper Research

All right, thank you very much.

Operator

And your final question comes from the line of Peter Mahon.

Peter Mahon – Dougherty & Company

Morning guys, just two final questions. You talked about having a 160,000 acres all by production, where do you kind of see that growing to by the end of the year and maybe by the end of 2012 season? You talked about having 250,000 to 260,000 core net acres. What kind of percentage of that will be held by production by maybe in 2012?

Thomas Nusz

So what we’ve been saying earlier was that we come in the year with 90,000. We thought we would convert through this year about 60,000 but that was kind of a little bit of high level math. What ends up happening is that as you drill some of these drill blocks that those leases actually will slop over on the adjacent drill blocks so you end up capturing a bit more.

And so, through this year where we thought we might be in 150 at the end of this year. We’re at 160 already with a couple of months yet to go so probably at the end of year, it’s probably going to be somewhere, maybe another 5,000 or 10,000 acres or something like that but if you start thinking about that and you say, “Okay.”

The ramping rate activity next year is totaled at 70 then we’re at 240. We’re getting pretty close to being balanced so it’s probably still going to be first quarter of 2013 but we think we’re in good shape and get everything held.

Peter Mahon - Dougherty & Company

I agree. And then, you know, kind of jump in – piggybacking on that, you really don’t see a promise with lease expiration especially in the core areas that you’re working on. Sounds like most of the core areas will be covered before in the exploration issues.

Thomas Nusz

Yes. I think we’re in real good shape and all in the acres that we want to hold.

Peter Mahon - Dougherty & Company

Perfect. Great. Thanks a lot, guys.

Thomas Nusz

Yes.

Operator

And the next question comes from the line of David Deckelbaum.

Thomas Nusz

Good morning, Dave.

Operator

David, your line is open.

Thomas Nusz

Did we lose him?

Operator

David, your line is open.

David Deckelbaum

I’m sorry if you all can’t hear me. I must be having some technical difficulties.

Thomas Nusz

No problem.

Michael Lou

We got you now.

David Deckelbaum KeyBanc Capital Markets Inc.

All right. Maybe it’s not me. All right. Glad I figured that out. So, back to the questions then. You talked about using 100% sand testing in Red Bank, North Cottonwood. Any other areas you think that might make sense to, you know, squeeze a little bit of a cost savings out or is it – risk over wood is not really compelling?

Michael Lou

Taylor may want to comment on it, but I think as you get over to the western or southwestern portion of Hebron, it may make a little bit of sense as you get down into Mondak but maybe those are probably be the two – well the far southern part of Mondak, those are two areas where it may make a little bit of sense.

David Deckelbaum KeyBanc Capital Markets Inc.

I guess to put another way, do you think that we have enough data yet on the entire, you know, inventory or wells drilled inventory today that suggest that you would see enough of a difference and you are using at 65, 35 ceramic sand mix?

Thomas Nusz

In the four areas where we’re using it now?

David Deckelbaum KeyBanc Capital Markets Inc.

Yes.

Thomas Nusz

We don’t have enough data yet. I don’t think there’s a – I mean, generally, it’s – I guess it’s probably four or five years before you really could say, “Hey, you know, here’s what, you know, I’d quantify what’s the difference maybe.

David Deckelbaum

Great. And then could you just refresh me quickly? As although the OWS spread comes in, shall we be thinking about the differential on cost there? I know that you have to charge, you know, third party to yourselves, but, you know, were they’d be any cost savings from using internal spread on a per well basis?

Thomas Nusz

Yes. And that’s roughly 20 million – 18 to 20 million on an annual basis reduction on our CapEx.

David Deckelbaum

Okay.

Thomas Nusz

If we talk about there’s two components of it. There’s the CapEx reduction because it’s just inner part – inner company transfer but then there’s a component of third party as well.

David Deckelbaum KeyBanc Capital Markets Inc.

Okay. And I guess, lastly, just, you know, on a salt water disposal impact to a living [ph] costs is – how do we think about the timing? I know that you’ve all guided up to the $3 account decrement in the cost blended next year. Should we see that by then pretty immediately in the first quarter of ’12 or see that sort of trending gradually over the year?

Thomas Nusz

It’s going to be pretty gradual throughout the year, Dave. You’re going to see it start to happen in that first quarter of next year but you’ll see that kind of gradually come in. It’s going to be a couple of things. One is the salt water disposal side of it and the other is just as you get more Bakken production it’s just going to continue to help us.

David Deckelbaum KeyBanc Capital Markets Inc.

Great. I think that’s all I have for now. Thanks, guys.

Thomas Nusz

Great. Thanks, David.

Operator

And there are no further questions at this time.

Michael Lou

Okay. Thanks again for everyone’s participation on our call today. I appreciate all the hard work and focus on continuing some improvement on the part of all the employees of Oasis and our key contractors in the office and in the field, and we appreciate the support that we continue to get from our strong shareholder base.

We look forward to sharing with you in December our capital plan for 2012 as we continue to execute on our tremendous inventory.

Operator

This does concludes today's conference call. You may now disconnect.

Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. However, we view them as an important resource for bloggers and journalists, and are excited to contribute to the democratization of financial information on the Internet. (Until now investors have had to pay thousands of dollars in subscription fees for transcripts.) So our reproduction policy is as follows: You may quote up to 400 words of any transcript on the condition that you attribute the transcript to Seeking Alpha and either link to the original transcript or to www.SeekingAlpha.com. All other use is prohibited.

THE INFORMATION CONTAINED HERE IS A TEXTUAL REPRESENTATION OF THE APPLICABLE COMPANY'S CONFERENCE CALL, CONFERENCE PRESENTATION OR OTHER AUDIO PRESENTATION, AND WHILE EFFORTS ARE MADE TO PROVIDE AN ACCURATE TRANSCRIPTION, THERE MAY BE MATERIAL ERRORS, OMISSIONS, OR INACCURACIES IN THE REPORTING OF THE SUBSTANCE OF THE AUDIO PRESENTATIONS. IN NO WAY DOES SEEKING ALPHA ASSUME ANY RESPONSIBILITY FOR ANY INVESTMENT OR OTHER DECISIONS MADE BASED UPON THE INFORMATION PROVIDED ON THIS WEB SITE OR IN ANY TRANSCRIPT. USERS ARE ADVISED TO REVIEW THE APPLICABLE COMPANY'S AUDIO PRESENTATION ITSELF AND THE APPLICABLE COMPANY'S SEC FILINGS BEFORE MAKING ANY INVESTMENT OR OTHER DECISIONS.

If you have any additional questions about our online transcripts, please contact us at: transcripts@seekingalpha.com. Thank you!

Source: Oasis Petroleum CEO Discusses Q3 2011 Results - Earnings Call Transcript
This Transcript
All Transcripts