Oasis Petroleum Inc.
Q2 2011 Earnings Call Transcript

Published: 9 Aug 2011

[Operator:]

Good morning. My name is April and I will be your conference operator today. At this time, I would like to welcome everyone to the Second 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. I will now turn the call over to Michael Lou, Oasis’ CFO to begin the conference. Thank you.

[Michael Lou:]

Thank you, April. This is Michael Lou. We’re reporting our second quarter ending June 30, 2011 results today and we’re delighted to have you on our call. Joining me today from the Oasis team are Tommy Nusz, President and 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 August investor presentation, which will be on our website after the call. 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 second-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 second quarter financial results, recent operational activity and our outlook for the rest of this year. I’ll begin with an operational update then hand the call back over to Michael to cover financial highlights and provide an update of our recently revised and approved 2011 capital budget. We may run a bit long today as we have a lot to cover but keep in mind we will be at EnerCom next week and we’ll have a chance to get in front of a number of you then. As outlined in the operational update in June, we expected to be challenged to maintain production at levels delivered in the first quarter and in fact, our production was 7,893 Boes per day in the second quarter, down 2% from the first quarter. That being said, we’re up significantly or 77% from the second quarter of 2010 and up 5% from our fourth quarter 2010 production levels. This is directly related to the unusual weather conditions and flooding we’ve experienced this year. You’re all familiar with the details associated with that so I won’t cover it again. More recently, conditions have improved significantly and we’re pretty close to being back to normal day-to-day operations. Currently, we only have one remaining well that’s shut in due to high water levels of the Missouri River and we expect this well to be back online within the next week. Our ability to move rigs and frac equipment and has been restored and existing water disposal system are fully operational. With the improved conditions and the great work from our operations team, we’re expecting strong growth in the third quarter and estimate production to come in between 11,000 and 12,500 Boes per day for the quarter. With a little more clarity around July production which was around 10,500 Boes per day, the recent weather improvement and some increase in operated activity we expect the annual volumes still to be in the full-year range of 11,000 to 12,500 Boes per day. Production in the second half of the year will be improved primarily due to one, our decision to move to 36 stage completion which have an average 20% to 30% in EOR than wells completed with 28 stages; two, the addition of our third frac crew which started in late June. With this crew, we will begin to work down our backlog wells waiting on completion. We’re expecting to be able to frac around three wells per month per crew, allowing us to work down the excess inventory over the next three months or so, and three, our land group has done an excellent job buying and trading acreage resulting in increase working interest in certain wells spud in late 2010 and drilling in 2011. During the second quarter, we brought on online 16 gross operated wells and a total of 13.5 net operated and non-op wells. Our operations team did an excellent job getting locations in relative high spots ready for frac jobs. As a result, we were able to obtain a number of one-off frac slots from idle factories that were waiting on their clients’ locations to be ready. We brought on production seven wells both in May and June and another six in July as of yesterday we had 23 gross operator or 18.1 net operated wells waiting on completion. So, we stayed relatively flat on that can as we get our third frac spread up and running efficiently. We’ve also been improving our spud-to-spud on the drilling side from 36 days to 31 days more recently at that phase we will effectively drill one more well per month with the same number of rigs. Additionally, the joint group has its running in an average of about 21 days spud-to-TD and 25 days spud to rig release for the 2011 wells to date compared to 31 days spud to rig release for our 2010 program. So an improved cycle times and the potential for going to 9 rigs by the end of the year our weighing off completion inventory level should normalize more in the 10 to 14 range. Another important tactical step that we’re making in order to protect our inventory is the launch of our in-house pressure pumping services with one frac spread at least initially. While we’ve seen a number of companies go down this path it is a significant step for us. So I’d like to spend some time going through how we think about it, but basically it boils down to inventory management, cost of service and the surety, consistency and continuous improvement of that service. Most importantly it really comes down to the power of our extensive drilling inventory that we control and the protection of that inventory especially the lower end that maybe not quite as price resilient. We’ve been considering this move for some time and essentially we’ve been working seriously on it for almost a year now. This move plays off of the success that we’ve already had with bringing services in-house albeit on a smaller scale primarily in metal tools and equipment. And honestly we likely wouldn’t be able to do it were it not for the significant amount of in-house expertise that we have. In June we formed a new company underneath Oasis Petroleum Inc., called Oasis Wells Services or OWS to provide pumping services to our operator wells. The crew is expected to begin operations in early 2012. The current operations team in our Williston office alone has over 100 combined years of experience in the frac business including experience with some of the larger providers as well as in pure start-up operations, most of that specifically in the Williston Basin. So managing the hiring operations, consumables and logistics is nothing new to our team. The broader overall economics of this decision are quite compelling to us. In total completions make up anywhere from 45% to 60% of our well cost. Pressure pumping services alone comprise about 30% to 40% of our well cost. And there’s a relatively higher margin embedded in each job. We’ll be able to capture that margin in the form of CapEx savings. So when we frac our own well, Oasis can save approximately $800,000 to $1 million per well gross, and that’s the way that you should think about modeling it. Additionally, we’ll earn a small profit margin on the services we provide to non-op partners, which would show up on our income statement and EBITDA in the neighborhood of about 300,000 per gross well-completed. For the year, if you assume the frac crude is, the proved frac is around 30 gross wells on a conservative side or 20 net wells, that would imply 16 million to 20 million of capital savings and an incremental $7 million to $9 million of EBITDA for the combined companies. Based on this, the incremental cash flow would be around $23 million to $29 million and this will discuss later that means there’s basically a one-year payback on our investment in equipment of $24 million for OWS. We’re also building a facility primarily to help this operation, but we’ll also use that for our production operations and that will be about $6 million. Overall, pumping services in the basin continue to be tight. We don’t see that changing any time soon even at the softening oil price environment, at least in the near term. So, OWS will provide us increase share and control on a tight market. Additionally, given our overall increased confidence and a resource potential on the basin, and what’s going to take to extract it over the long term, more control of our cost structure is important to us. Since the Bakken is present across all of our acreage, our operations into some conventional play, can look more like manufacturing process that is typical conventional play and you’ve heard us say that many times. While oil has obviously come up sharply in the recent days, we expect to maintain our plan to exit 2011 with nine rigs and be a 12 rigs some time in 2012. That being said, we will be monitoring oil price closely and expect to be prudent when it comes to managing our rig fleet maintaining flexibility. Again, at the strip adding our fourth frac crew in the first quarter of 2012 aligns with our strategy to implement 12 rigs by the end of 2012. As you know, we currently have seven rigs running, six on the west and one on the east and have contracted to pick up our eighth rig and expecting the mines in the fourth quarter. The east rig will be driven on the west on the on the 9th we’ll begin working on the east. On our last call we discussed relationships we have of third parties to build out our oil and gas infrastructure and our internal build out of salt water disposal systems or SWD systems. Given the weather conditions we have this year these efforts have been a key focus for us in order to ensure we can maintain production should we have another tough winter. On the gas side, we have arrangements with third parties to connect wells in Red Bank, Indian Hills, Hebron and Mondak on the west side of the basin and the southern portion of our Cottonwood position on the east side. While we currently have some limited gas production being solved majority of our gasses currently being the player. We expect the completion of the gathering and infrastructure on the fourth quarter but some of the wells have already come on line. This will add about 6 million to 7 million cubic feet per day to our net production of the fourth quarter compared to 2.3 million as a baseline in the second quarter. Under the percent of proceeds contracts we expect to receive Henry Hub plus 10% to 15% given the high liquids content of the gas production. These all falls to bottom line since we have no other operating cost associated with the operations. The oil gathering system that’s being built by another third party is moving forward. We expect our wells in Red Bank, Indian Hills and Hebron to be connected late in the fourth quarter or early 2012. As everyone knows, this should help take a considerable amount of thrust up the roads and we’ll ensure that oil gets to market during tough winter conditions. The oil infrastructure will enable us to eliminate the cost of trucking oil which can range from $3 to $5 a barrel which will immediately impact our realized prices. We will pay a fee per barrel which will show up as marketing and gathering costs for approximately $2 to $3 a barrel. So net-net, we’ll improve profitability by $1 to $2 per barrel. With the gathering system in place, we will also have the ability to optimize pricing by nominating our barrels at different delivery points along the system and will likely start taking over some of the marketing responsibilities and take advantage of that. Finally, the SWD investment is a critical element of our infrastructure as it significantly reduces the cost to disposed water – disposal water in the basin. Disposal systems again will limit trucking and allow us to deliver oil during tough weather conditions. Because we have large operating blocks which enable us to capitalize on operating efficiencies, we’ve accelerated growth profile, we’re accelerating capital from 2012 into 2011, and we’ve increased our capital budget for SWD infrastructure this year by close to $15 million up to 36 million. With this infrastructure in place, we can reduce aggregate net income to LOE by approximately $1 per barrel of oil equivalent. The benefit of this initial investment begins to show up in the fourth quarter of ‘11 and the incremental capital should show impact in 2012. Now, let’s transition to a discussion on production and well performance. You’ve heard us say consistently that we will stay away from providing well specific information unless we have something to report that we think is meaningful to the asset base and to our inventory. We’ve talked about the transition to 36 days completion and so far results to very encouraging. Based on comparison of the first 90 days of production for three areas, South Cottonwood, North Cottonwood and Red Bank, where we have sufficient production data. We are seeing an increase in production of approximately 25% to 40%. For example in South Cottonwood, our 236 stage wells produced a key noted average of 62,000 barrels in the first 90 days. In the prior 328 stage wells, it produced key with an average of 44,000 over a similar time period for 43% uplift so far. We have also discussed the fact that we’re drilling five to six Three Forks wells in 2011. Of these, we currently have two producing. As you know, it’s still early days when it comes to evaluating the Three Forks wells but we are comfortable that their oil resource is there. Early days but we do see the Three Forks of a bit different animal in the Middle Bakken, we have a lot to learn. But we’re encouraged by what we’ve seen so far. In general, the Three Forks interval has more variability in reservoir quality in rock mechanics than we’ve seen in Middle Bakken. And as a result, just here in well drilling and frac design are even more critical. But the wells that we’ve stimulated so far, they’ve generally treated at higher pressures and in wells that we have steered out of the better quality rock has been very difficult to frac some of those stages at all. For comparison in Indian Hills, our 36 stage Federal Middle Bakken well produced approximately 35,000 Boes over the first 30 days on production and the high stead Three Forks well about 2 miles away produced approximately 26,000 Boes over the first 30 days during a tough operating environment. So very strong results in both zones and our 23,000 net acre concentrated block and consistent with other wells in the area but a bit less in the Three Forks. We’ve completed our first Three Forks well in the Hebron block as well the Williston federal. While we’re encouraged by what we’ve seen, we’ve had some challenges in completion. I think the number of stages that we effectively completed is somewhere less than 20. This is why believe it’ll be very important to stay in zone in order to get all of our frac stages off effectively. The Williston federal has produced about 8,000 barrels of oil in the first 30 days or about 260 barrels of oil a day and this performance can be attributed to the number of stages that we effectively got on, so still lot to learn about Three Forks in this particular area. The last operations item I’d like to cover is our land position. While the overall balance of our net acres has remained relatively flat over the last year, our land group has done a tremendous job with consolidating our core areas and upgrading the overall quality. In the first half of this year, we’ve acquired approximately 3,400 net acres in our core areas at an average cost of about $1,200 per acre or with the commitments that we obtained prior to the first half – in the first half of the year, the total of approximately 7,200 acres at roughly $700 per acre. We also traded acreage which resulted in the addition of approximately 3.4 net wells to our 2011 operated drilling program. We’re still tabulating all of the data but hope to be in a position to give you more color around the evolution of our acreage position next week at EnerCom. In a moment, I’ll turn the call over to Michael to discuss our financial results. But before I do, I wanted to acknowledge Michael’s recent promotion to Chief Financial Officer. Michael joined us in 2009 and did a tremendous job leading us through our very successful IPO process. He’s been a key contributor to our strategic direction in our leadership team, this appointment is well observed. Congratulations, Michael. With that, I will now turn the call over to him to discuss our financial results.

[Michael Lou:]

Thanks, Tommy. Let’s start by discussing in a little bit more detail our decision to increase our CapEx budget from $490 million to 627 million. While the 28% increase to capital seems like a lot, we’ve talked about a fortune of the increase in the past. We can first focus on the drilling and completions portion of the capital budget which now totals $527 million. On our last call, we discussed total CapEx likely going from $490 million to approximately $550 million due to increasing from 28 to 36 stages cost creep and bringing in rigs 8 and 9. At the time, we had not finalized the numbers due to timing of some of these pieces, but since then we’ve moved down the road in solidifying most of these services. In the press release issued last night, there’s a breakdown of each component of our increase which leave three pieces totaling about $67 million and bringing our budget to $557 million. So this portion of the capital increase should come as no real surprise. Of this increase, approximately $19 million was due to cost creep which we talked about on our first quarter call. The additional $70 million of capital increase towards 2011 budget will really have more than impact on 2012 and beyond. Tommy mentioned how our land group has done a great job on trading acreage and adding net wells or additional working interests to our 2011 operated wells. Most of this increase will impact wells in the second half impacting production late this year and into 2012, and driving about $19 million of additional capital this year. Other items in our E&P budget includes land acquisitions, G&G and infrastructure, which increased by $11 million primarily due to $14 million of increase toward infrastructure budget bringing forward the benefit of salt water disposal wells and pipelines. This increase was offset by a slight reduction in our G&G capital for 2011. And as Tommy mentioned, we will spend $24 million on equipment for OWS. This capital is clearly an investment in our future. We expect it to be a strong return on investment project, as well as a key component of our operations, which is expected to lower well cost in 2012 and beyond. The budget includes $6 million for our field office in Williston, North Dakota to house our E&P and OWS operations. The $10 million of other non-E&P CapEx includes other equipment such as drill pipe. This equipment is purchased today and then rented to our future wells and will create savings to the future well cost. We talked about this in the past but if certain well costs become too expensive, where it makes sense to bring pieces in-house, we will consider it. Overall, most of our capital investment increases wider growth, future production or offset costs. The economics of our salt water disposal system in OWS are highly compelling and our investment in new wells continue to bring forward the economics of our inventory. We ended the quarter with $425 million of cash and short-term investments on the balance sheet, which should allow us to effectively execute on our operating plan and capital investments into 2012. Additionally, we have a $137 million revolver that should continue to grow as we add new reserves as well. We also continue to hedge a bit more aggressively in order to protect future cash flows in our base level drilling plan. We have 8,500 barrels per day hedge for the remainder of 2011 and recently increased 2012 hedges to 11,500 barrels per day and 2013 hedges to 4,000 barrels per day. Despite relatively flat production levels from the first quarter, we had a record quarter on revenues at $67 million and adjusted EBITDA at over $44 million. This was driven in the second quarter by an average realized price of $95.48 per barrel, which includes just a 6.8% differential to NYMEX from 12.7% differential on the first quarter. The differential was positively impacted primarily by the impaired Canadian thin crude production into the U.S. which has helped to drive up the demand for Bakken’s sweet crude in Clearbrook and Guernsey. This is probably a short term move and differentials will likely widened to more normal levels once the Canadian thin crude plant get back to normal operations. LOE came in at $8.63 per Boe for the quarter, up $0.47 over the first quarter. This is due to higher cost in the quarter driven by weather coupled with lower production. We still expect LOE costs will come in between $5.00 and $7.00 per Boe for the year or be it in the higher end of the range. In conclusion, while the first half of the year had been challenging, we look forward to an exciting second half of the year ahead of us. We have the right team in place to execute the increased drilling and completion activity, and considerable production growth all of our implementing measures to reduce well cost and LOE. With that we’ll turn the call over to April to open the line for questions.

[Operator:]

(Operator Instructions) Your first question comes from Dave Kistler with Simmons & Company.

[Dave Kistler:]

Good morning, guys.

[Thomas Nusz:]

Good morning, Dave.

[Dave Kistler:]

Real quickly just to put the OWS savings into perspective. Can you guys give us you latest well cost and In that way we can kind of take the numbers you gave us back into the incremental savings?

[Thomas Nusz:]

Yes. The current well cost for the 36 stages, 65% ceramic, 35% sand is 9.2, 9.3.

[Dave Kistler:]

Okay.

[Thomas Nusz:]

So it be 800 to a million off of that.

[Dave Kistler:]

Okay. Great. And then, I kind of thinking about that in terms of the current commodity price environment what does that imply for a rate of return for those wells and is there a price where even with these cost savings that you’re incorporating. Do you consider decelerating activity?

[Thomas Nusz:]

The question is what’s the impact to rate return with this low cost?

[Dave Kistler:]

That’s the first thing and then the second thing from it would be at what commodity price would you guys adjust that activity irrespective of the cost savings you guys have?

[Thomas Nusz:]

So the rate of return is going to depend on the area. $1 million reduction of our mine to total low costs is going to have a pretty significant impact. And as Tommy talked about, one of the places that makes really compelling to us is some of the areas that are a little more marginal at low price.

[Michael Lou:]

Yes, David, that lower recovery, it’s somewhere in the 5% range and higher recoveries in that number maybe closer to 10% to 15% just uplift on absolute percentage points. Right, Michael?

[Michael Lou:]

Correct.

[Taylor Reid:]

5% then 15% is the highest of the high end. So, for instance, David you took an $85 oil price at the low end of the type for ranges and you had a 20% pre-tax IOR before lowering it by $800,000 to $1 million would probably push you up about that five percentage points on a pre-tax IOR business. As you get to the higher end of the tax range, if you’re at all the 80% IOR on the higher side of things, that $85, it can drive you north of 100% on terms of a pre-tax IOR.

[Dave Kistler:]

Okay, that’s very helpful. I appreciate it. And then just one last one, let somebody ask on. How big do you guys think about growing OWS over time? You set it up as a separate entity, clearly last to report it a little differently or breakup financials differently. Is it something you anticipate growing and then eventually spending out or am I reading too much into that?

[Michael Lou:]

Yes, probably a bit early to head down that path at this point. We’ll just – I mean, we’ll start with this one, with this spread and kind of see where it takes us once we’ve got some real activity on our belt.

[Dave Kistler:]

Okay, that’s helpful. I’ll let somebody else jump on hop back in the queue. Thanks, guys.

[Thomas Nusz:]

Thanks, Dave.

[Operator:]

Your next question comes from the David Heikkinen from Tudor Pickering.

[David Heikkinen:]

Good morning, guys. And Michael congratulations on your promotion.

[Michael Lou:]

Thank you.

[David Heikkinen:]

And Tom, as you think about Oasis Wells Services and I’m trying to think about uptime on one frac actually for the 30 or so wells. What is the – what is your expected uptime on that equipment?

[Thomas Nusz:]

We – I mean if you see, if you look at it there’s what we typically talk about, there’s three wells per month, per spread. So that would be 36 wells per year. We’re home at 30 to start just by virtual timing and shake down. But we’ll handle solid that uptime crews on redundancy. So I mean, we know we’re going to need some equipment redundancy because, and this is pretty intense work for this iron. So, we’re handling some of that, just by handling more of it.

[David Heikkinen:]

Okay. So thinking about other operators on the E&P side that have built frac equipment, you guys having a couple frac fleets next year and having some back up and spending another $24 million or so isn’t unreasonable as we think about it.

[Taylor Reid:]

Yes. So what we’re likely to do is, as Tommy said, start with this one frac fleet where we’d like to probably get to is to cover 30% to 50% of our capacity of frac. And the idea being, the 30% to 50% we’re at high activity levels. So if we do have a pullback, we’ll be able to provide closer to 100% of our activity in a down environment. If it does work out effectively as we go to 12 rigs, we could add a second spread that could potentially be next year but I would say, if you do it, it’s probably later in the year or early the following. But we got to see how it works to get it up and running.

[David Heikkinen:]

Yes. Okay. And then on the rig side, you all have had to continue deficiency improvements as you’ve even added rigs. As you go to 12 rigs running, do you expect any deterioration in drilling time or as those rigs come up and start running or do you think we should just think about the kind of standard that you set now around the seven-rig program?

[Thomas Nusz:]

Yes. David, if you look at it, we’ve actually had a significant amount of improvement over the last year, say, since we IPO-ed while in the face of increasing rig counts. So the organization is done really well, continuously improving our processes in spite of having basically doubling of activity.

[David Heikkinen:]

Okay.

[Michael Lou:]

So, I would expect us to at least stay flat.

[David Heikkinen:]

Okay. And then with those things in mind and kind of spending that you gave for Dave’s first question, can you walk us through a run rate CapEx for 2012 than with 12 rigs running?

[Michael Lou:]

Yes. So it’s probably going to be somewhere in the 750 or maybe 800 range. I mean, it’s a bit early.

[David Heikkinen:]

Yes.

[Michael Lou:]

I mean, there’s a lot of moving parts. Obviously, if we can keep improving efficiency, we may not need 12 rigs that accomplish the same objectives. So, but just for scoping purposes at this point, that’s probably not a bad range.

[David Heikkinen:]

Okay. Thanks, guys.

[Michael Lou:]

Thanks.

[Operator:]

Your next question comes from Ron Mills with Johnson Rice.

[Ron Mills:]

Good morning, guys.

[Thomas Nusz:]

Good morning, Ron.

[Ron Mills:]

A lot of answers on the OWS financer, can you – of the one part of your calculation on the cost savings in terms of the incremental cash flow? I think what you had said is $23 million to $29 million of incremental cash flow in one year, is that from the combination of the cost savings plus the non-op profit margins so you’d have kind of $1 million to $1.3 million of cost savings per wells? Is that how you got to that number?

[Thomas Nusz:]

Yes, exactly. So Tommy mentioned $800,000 to $1 million dollars of savings per well, called 30 gross wells in a year or 20 net.

[Ron Mills:]

Right.

[Thomas Nusz:]

Because that 20 net gets you to 16 million to 20 million of annual capital savings for us. And then on the non-op portion of that or the other kind of called 10 net wells, you’re going to make some small profit margin there and that’s going to be around about 7 million to 9 million of EBITDA there.

[Ron Mills:]

Okay, great. And then, the $24 million that you have for this frac fleet, what’s – how are you sizing that frac fleet in terms of required horsepower rate in redundancies so just what’s your overall horsepower purchase?

[Thomas Nusz:]

Right now with the horsepower purchase it’s about 18,000 horsepower. To frac we need, kind of 12,000 horsepower levels so you got redundancy between 12 and 18 depending on the well. And – so it will be in this way, eight units and eventually we’ll get to 10 but we’ve got two spare units while you’re frac-ing on the job.

[Ron Mills:]

Okay and then when you point to your production guidance, obviously your third quarter, back to normal the implied fourth quarter run rate would be somewhere even north, I don’t know what we’re expecting but somewhere in the 17,000 or 18,000 barrel a day range for the fourth quarter which sets up a strong 2012. Based on what you talked about the CapEx run rate to David’s question. How do you have rigs 10, 11, 12 coming into your capital plan to get to that CapEx level so we can start thinking about the 2012 production ramp?

[Michael Lou:]

I think, Michael, you can correct me, well, I think the way the guys have at model is basically one in the second, one in the third and one in the fourth.

[Thomas Nusz:]

That’s right.

[Ron Mills:]

Okay. I’ll let someone else jump in. Thanks, guys.

[Thomas Nusz:]

Thanks, Ron.

[Operator:]

Your next question comes from William Butler from Stephens.

[William Butler:]

Good morning.

[Thomas Nusz:]

Good morning, William.

[William Butler:]

Also a follow-up on the frac where I’m in, it says – when do you all expect that to arrive, the newbuild, assuming it’s a new build?

[Thomas Nusz:]

Yes. It’s all newbuild equipment and it’ll start better and in probably October timeframe, but there’s different cycle time on each component of it. So that’s why we say first half of next year maybe if things go right, it’ll be the first quarter before we’re operational. And then obviously we’ll have some shape now after that.

[William Butler:]

Okay. And that will not display, as one of the three you’ve got currently that be added as a fourth, right?

[Thomas Nusz:]

Yes. Basically, that would get us aligned with the 12 rigs.

[William Butler:]

Okay. And then what’s – when you all ran the analysis on that, what the payback period on buying out?

[Thomas Nusz:]

Just cash on cash return on the initial investments it’s going to be, Michael, – I mean, that’s going to be a year.

[Michael Lou:]

It’s going to be basically a year. Okay. So we went through it before 16 to 20 million of capital savings. We’re aiming at 7 million to 9 million of outside EBITDA, so will get you to about $23 million to $29 million of incremental cash flow for the first full year of operations. So it drives around one year payback.

[William Butler:]

Okay. And then are you all doing any more testing on down spacing in fracing? Can you talk a little bit about any communication you may or may not be seeing between Middle Bakken and Three Forks?

[Thomas Nusz:]

Yes. Taylor can – I mean, the guys have been doing a bunch of work on it. We haven’t done any in-fill pilots yet and I know we’ve got some coming up, activity over that.

[Michael Lou:]

Yes. We participated in a number of wells that are testing , waters pacing both Middle Bakken and Three Forks, so we do have some data on that front, we had planned for later this year and early next year to make co-pilots both Bakken -in a go-distance in Bakken’s Three Forks and we’re testing a variety of distances. So we don’t – we haven’t come up with the exact density that we’ll end up with for down spacing. We think we will have that answer by mid late next year at which time; we’ll be going into full down spacing and add drilling on the wells,

[William Butler:]

Okay. And then it looks like you all let a small bit of acreage expire during the quarter. How much was associated with the charge and then are you all planning to let any more acreage expire?

[Thomas Nusz:]

Yes, hold on, as you know its land position is moving all the time.

[Michael Lou:]

Well, Michael put off the charge side of it, comment on where the acreage was that expired. We had some land on the east side of the basin. Most of that up in St. Croix, which is very north-side of our East Nesson position and we let some of that acreage expire in that area just due to the economics that we’re seeing from the well that we drilled in that area. We talked about that before we’ve actually taken that out of our inventory. At this point, we will most likely drill an additional well up there, may be next year but again, right now, it’s out of our economic inventory.

[Thomas Nusz:]

And it’s had $1.5 million charge. I think what you’ll see is that over the next couple of years, as Taylor mentioned, some of that acreage that falls outside of our inventory will likely let go or release. But it’s about one and half months right now.

[William Butler:]

Okay. Great, thanks. Look forward to seeing you again next week.

[Thomas Nusz:]

Thanks.

[Operator:]

From Marcus Talbert from Canaccord.

[Marcus Talbert:]

Good morning guys.

[Thomas Nusz:]

Good morning.

[Marcus Talbert:]

Just following up on William’s question here. I’m looking at the budget for next year. It seems like you’re trading more acreage right now and coring up. Are you thinking kind of a flattish number for what’s going to be allocated for the land budget next year?

[Thomas Nusz:]

Yes, it’s always a difficult number to forecast and you guys heard us talked about this before. We kind of view at this as having a normal land load and that run rate is – we call it $20 million. We’re a little bit behind on that this year just competitive it is. But as we go on the next, I don’t have the guys who have modeled it but it probably will still be 20 million at least for scoping purposes.

[Marcus Talbert:]

Okay. Thanks very much and then I guess just looking at the production rent in the back half of the year here. It looks like you need sort of a sequential average of about 45% in Q3 and Q4. If I’m doing the math right and you guys just sort of talk about a backlog of 8 to 10 wells before, are you pretty confident that you can complete the wells needed in each of the quarters to sort of achieve that guidance?

[Thomas Nusz:]

The guidance is modeling out well by well. So we had a little bit, but it’s all bounced out.

[Marcus Talbert:]

Understood. And so you’re – in terms of completions, we should be thinking 25 plus completions for each quarter in the back half of the year here?

[Thomas Nusz:]

Yes, we’ve been running essentially it’s seven a month that’s 21. So that will pick up a bit – that’s probably a bit more than once we get these – all these frac is up and running that it’s probably more like debit then incremental crude, Taylor, it’s...

[Michael Lou:]

You’re going to be mid- to high 20s per quarter.

[Thomas Nusz:]

Yes.

[Marcus Talbert:]

Okay.

[Thomas Nusz:]

Because what we’ve said in the – what we said is that bringing on that third frac crew is going to be incredibly important for us to be able to work down that inventory. And so, that just started in July. We got to work out some of the case plan when any of these come on, but should be going really full bore going forward to the rest of the year.

[Marcus Talbert:]

Okay. Thanks, guys very helpful. And you provided some great color on the new well service venture. We heard last night about these new frac sleeve technology yielding time savings by eliminating the I guess the line item and some of the early stages. Is this that concept that you guys have tested or are there any other outside concepts that may eventually speed this up a little bit?

[Thomas Nusz:]

Taylor may want to add to this, but we play it a little bit with some of the combo jobs of sleeves out on the sale, but for us I think the surety of plug and perf the efficiency that we’re able to do those jobs I think will continue to be oriented that way, keep in mind that with these – as you continue to develop the sleeve technology basically what you’re trying to duplicate is this plug and perf but on a more efficient basis but we’ve done some of these things, Taylor, 36 stages in 5.5 or 6 days so if we can do them – that probably at this point, it’s probably a P10. If we continue to do all with that efficiency, I think we’ll continue to be oriented in that way.

[Operator:]

Your next question comes from Marty Beskow with Northland Capital.

[Marty Beskow:]

Guys.

[Thomas Nusz:]

Morning.

[Marty Beskow:]

Considering the volatility in oil prices right now, roughly to what level do you think oil would have to get to before you’d make some adjustments in your production plans?

[Thomas Nusz:]

Probably, Michael, I would guess probably somewhere in this sub-70 range for some extended period. Keep in mind that oil and just in the last 10 days. It’s dropped $16 or $17. And with that, keep in mind too that we’re given premiums, the WTIs. We trade at Clearbrook and guarantee of Clearbrook. As of yesterday, it was about $7.5 up, so be mindful of that as well. But I think as we see some visibility, that oil in a 6 to 12-month window would be sub-70. I think we would have to scale back a bit.

[Marty Beskow:]

And what do you estimate your breakeven as right now?

[Thomas Nusz:]

Breakeven in terms of?

[Marty Beskow:]

In terms of oil price.

[Thomas Nusz:]

Yes. I think if you would look at the total of the inventory we did some work on this last week, the total of the inventory breakeven was somewhere in that $70, $75 range. We’ve got a lot of our inventory that’s resilient down to some pretty low oil prices in the $50 to $60 range we improve on that by having our own services too but I mean in fairness, if oil prices are low for prolonged period $50 to $60, services will likely adjust. We got some of the inventories that break – the break over is somewhere around 80

[Michael Lou:]

And that’s all that current ball cost so as Tom had mentioned it prolonged to $80, $70, $60 oil price most likely those services cost come back down as well.

[Marty Beskow:]

Okay. All right, thank you.

[Operator:]

Your next question comes from Ron Mills.

[Ron Mills:]

On your comments you told me about the Three Forks. How many more Three Forks do you have planned this year? And maybe even if you have an outlook into next year, just to try to or what do you think it’ll take to do the evaluations in comparisons needed for between the Middle Bakken and the Three Forks to collect that data?

[Thomas Nusz:]

I think six or seven this year, Taylor? And keep in mind that one of the things we talked about was variability. If you look at the wells that we just diced at well in Indian Hills it’s pretty strong, we get over to Hebron, I feel like we can make it work but we’ve got to figure out ways to get all of the stages fracked more effectively. As we go into next year, I don’t know what you guys have in terms of Three Forks well. I don’t know if we’ve gotten that far yet as to coming up with a numbering of exactly your – or a decent range on Three Forks wells for next year but it’s probably not a whole heck of a lot different than this year.

[Ron Mills:]

Okay. And then just to follow up on my earlier comment about production. To get to your fourth quarter rate, and some of this will just be the benefit of that third crew and going through the backlogs but I mean, does it – it seems like you would need to be somewhere close to 20,000 Boes per day of production exiting this year. Is that about the right range to get to that fourth quarter average?

[Thomas Nusz:]

What do you call an exit?

[Ron Mills:]

12/31.

[Thomas Nusz:]

On the day?

[Michael Lou:]

Yes. That’s probably not far off.

[Ron Mills:]

Yes. Okay. Okay, great. Thank you, guys.

[Michael Lou:]

You bet.

[Operator:]

Your final question comes from Brian Kuzma from Weiss Multi-Strategy.

[Brian Kuzma:]

Hey. Good morning, guys.

[Taylor Reid:]

Good morning, Brian.

[Brian Kuzma:]

I just had I guess a follow-up on the kind of worst case scenario here, given the rigs and the crews that you guys have contracted, what’s the flexibility for coming back next year if you wanted to?

[Taylor Reid:]

Yes. So, I mean, a couple of things. What we’re trying to do is we’re one, we’re upgrading our drilling fleet and we kind of think about it as, if we can continue to run, at least in our mind, given the inventory that we have, that resilient down to those lower oil prices, call it $50 to $60 and we can continue to run five rigs drilling that inventory. And so, we’re comfortable with having long-term contracts on five rigs, I think right now we’ve got, Taylor, three?

[Thomas Nusz:]

Yes, three. They’re over a year.

[Michael Lou:]

That are over year and the rest of them are staged out within 12-months. So it gives us a lot of flexibility there.

[Brian Kuzma:]

And then how does it work with the pressure pumping crews?

[Thomas Nusz:]

Yes, same type of thing. I think we’ve got one crew that’s...

[Michael Lou:]

So we’ve got one...

[Thomas Nusz:]

24 months...

[Taylor Reid:]

Yes, one that’s a little less than 24 months now, one that’s 18 and one that was six and those that we’ve worked a couple of months off of each of those. So their laddered similar to the rigs, they’ve got flexibility to drop back.

[Brian Kuzma:]

That’s perfect, that’s one I needed. Thanks.

[Operator:]

Your final question comes from Irene Haas from Wunderlich Securities.

[Irene Haas:]

Hi, just one last question. I mean, you guys are got to go into Petrolling mode next year. I’m kind of wondering on sort of a pro-well basis, once you get all your efficiency gain and some critical math. What’s your per well drilling in completion cost be in that particular and sort of manufacturing mode in 2012?

[Thomas Nusz:]

Got it, I think the way the guys are looking at, it is that set up Pumping Services business aside. And without that it’s probably somewhere in the 10% to 20% range, Taylor, I mean it’s a bit early because they have done a whole lot of it, yes, other than where we’ve done those back-to-back wells or we’ll drill 12/80 North and 12/80 South and the well heads are less than 100 feet apart and then we’ll frac those wells back and forth and we were doing that latter point of last year.

[Michael Lou:]

Right. So we’ve been there.

[Thomas Nusz:]

So we’re gathering some data just based on that. But keep in mind that we haven’t done in terms of full blown pad drilling. We haven’t done anything other than that at this point.

[Irene Haas:]

Great. Thanks.

[Thomas Nusz:]

You bet.

[Operator:]

At this time, we have no questions in the queue.

[Thomas Nusz:]

Okay. Well, thanks again for everybody’s participation in the call today. I appreciate all the hard work and focus on continuous improvement. On the part of all the employees at Oasis, in the office and in the field, we appreciate the support that we continue to get from our strong shareholder base. As I’ve mentioned, we’ll be at EnerCom next week and look forward to seeing many of you there. Thanks.

[Operator:]

This concludes today’s conference call. You may now disconnect.