EXHIBIT 99.2

Title: Oasis Petroleum CEO Discusses Q2 2011 Results — Earnings Call Transcript
Symbol: OAS
Call Start: 10:00 am CDT
Call End: 10:55 am CDT

Oasis Petroleum (OAS)
Q2 2011 Earnings Call
August 9, 2011 10:00 am CDT

Executives

Tommy Nusz — President and Chief Executive Officer
Taylor Reid — Executive Vice President and Chief Operating Officer
Michael Lou — Executive Vice President and Chief Financial Officer
Roy Mace — Senior Vice President and Chief Accounting Officer
Richard Robuck — Director of Investor Relations

Analysts

David W. Kistler — Simmons & Company
David M. Heikkinen — Tudor Pickering
Ronald E. Mills — Johnson Rice
William Butler — Stephens
Marcus Talbert — Canaccord
Marty Beskow — Northland Capital
Brian L. Kuzma — Weiss Multi-Strategy
Irene Haas — Wunderlich Securities

Presentation

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. Good morning, everyone. This is Michael Lou. We are reporting our 2^nd quarter ending June 30, 2011 results today and we are 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 posted to the website.

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 than 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 2^nd 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 will now turn the call over to Tommy.

Tommy Nusz

Good morning and thank you for joining us this morning to discuss our 2^nd quarter financial results, recent operational activity, and our outlook for the rest of this year. I will 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 will 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 1^st quarter and, in fact, our production was 7,893 boes per day in the 2^nd quarter, down 2% from the 1^st quarter. That being said, we are up significantly, or 77%, from the 2^nd quarter of 2010 and up 5% from our 4^th quarter 2010 production levels. This is directly related to the unusual weather conditions and flooding we have experienced this year. You are 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. We currently only have one remaining well that is 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 has been restored, and existing water disposal systems are fully operational.

With the improved conditions and the great work from our Operations team, we are expecting strong growth in the 3^rd 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 improvements, and some increase in operated activity, we expect 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:

1)

Our decision to move to 36 stage completions, which have an average 20 to 30% greater production and EURs than wells completed with 28 stages

2)

The addition of our 3rd frac crew, which started in late June. With this crew we will begin to work down our backlog of wells waiting on completion. We are expecting to be able to frac around 3 wells per month per crew, allowing us to work down the excess inventory over the next three months or so; and

3)

Our land group has done an excellent job buying and trading acreage resulting in increased working interest in certain wells spud in late 2010 and drilling in 2011.

During the 2nd quarter, we brought 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 frac crews that were waiting on their client’s locations to be ready. We brought on production 7 wells both in May and June, and another 6 in July. As of yesterday, we had 23 gross operated or 18.1 net operated wells waiting on completion. So we have stayed relatively flat on that count as we get our 3^rd frac spread up and running efficiently. We have also been improving our spud to spud on the drilling side from 36 days to 31 days more recently. At that pace, we will effectively drill one more well per month with the same number of rigs. Additionally, the drilling group has us running at 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, with improved cycle times and the potential for going to 9 rigs by the end of the year, our waiting-on-completion inventory level should normalize more in the 10-14 range.

Another important tactical step that we are 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 have seen a number of companies go down this path, it is a significant step for us, so I would like to spend some time going through how we think about it. But, basically it boils down to Inventory Management, the 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 have been considering this move for some time and have essentially been working seriously on it for almost a year now. This move plays off of the success that we have already had with bringing services in house, albeit it on a smaller scale, primarily in rental 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 Well Services, or OWS, to provide pumping services to our operated 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 45-60% of our well costs. Pressure pumping services alone comprise about 30% to 40% of our well cost. And there is a relatively high margin imbedded in each job. We will be able to capture that margin in the form of CapEx savings. So when we frac our own well, Oasis can save approximately $800 thousand to $1 million per well, gross. And that is the way you should think about modeling it. Additionally, we will earn a small profit margin on the services we provide to non-op partners, which would show up on our income statement as EBITDA in the neighborhood of about $300 thousand per gross well completed. For the year, if you assume the crew fracs around 30 gross wells on the conservative side, or 20 net wells, that would imply $16 to 20MM of capital savings and an incremental $7-9MM of EBITDA for the combined companies. Based on this, the incremental cash flow would be around $23-29MM, and as we will discuss later, that means there is basically a 1 year payback on our investment in equipment of $24MM for OWS. We are also building a facility primarily to house this operation, but will also use that for our production operations, and that will be about $6MM. Overall, pumping services in the basin continue to be tight and we don’t see that changing anytime soon even in a softening oil price environment, at least in the near term. So OWS will provide us increased surety and control in a tight market.

Additionally, given our overall increased confidence in the resource potential in the basin and what it is going to take to extract it over the long-term, more control over our cost structure is important to us. Since the Bakken is present across all of our acreage, our operations in this unconventional play tend to look more like a manufacturing process than a typical conventional play, and you have heard us say that many times.

While oil has obviously come off sharply in the recent days, we expect to maintain our plan to exit 2011 with 9 rigs and be at 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 and maintaining flexibility. Again, at the strip, adding our 4^th frac crew in the 1^st quarter of 2012 aligns with our strategy to implement 12 rigs by the end of 2012. As you know, we currently have 7 rigs running — 6 on the west and 1 on the East, and have contracted to pick up our 8^th rig and expecting the 9^th in the 4^th quarter. The 8^th rig will begin drilling in the West and the 9^th will begin working in the East.

On our last call, we discussed relationships we have with third parties to build out our oil and gas infrastructure and our internal build-out of saltwater disposal systems, or SWD systems. Given the winter conditions we had 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 sold, the majority of our gas is currently being flared. We expect the completion of the gathering and infrastructure in the 4^th quarter, but some of the wells have already come online. This will add about 6-7 mmcf per day to our net production in the 4^th quarter compared to 2.3 mmcf as a baseline in the 2^nd 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. This all falls to the bottom line, since we have no other operating costs associated with the operations.

The oil gathering system that is 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 4^th quarter or early 2012. As everyone knows, this should help take a considerable amount of trucks off the roads and will 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 $3-5 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 of approximately $2-3 a barrel. So, net net, we will improve profitability by $1-2 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 responsibility to take advantage of that.

Finally, the SWD investment is a critical element of our infrastructure, as it significantly reduces the cost to move disposal water in the basin. Disposal systems, again, will eliminate trucking and allow us to deliver oil during tough winter conditions. Because we have large operated blocks, which enable us to capitalize on operating efficiencies, and we have an accelerating growth profile, we are accelerating capital from 2012 into 2011 and have increased our capital budget for SWD infrastructure this year by close to $15MM up to $36MM. With this infrastructure in place, we can reduce aggregate net company LOE by approximately $1.00 per Boe. The benefit of this initial investment begins to show up in the 4^th quarter of 2011 and the incremental capital should show impact in 2012.

Now, let’s transition to a discussion on production and well performance. You have 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 have talked about the transition to 36 stage completions and, so far, results look 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 two 36 stage wells produced a cumulative average of 62,000 barrels in the first 90 days and the prior three 28 stage wells produced a cumulative average of 44,000 over a similar time period for a 43% uplift so far.

We have also discussed the fact that we are drilling 5 to 6 Three Forks wells in 2011. Of these, we currently have 2 producing. As you know, it is still early days when it comes to evaluating the Three Forks wells, but we are comfortable that the oil resource is there. Early days, but we do see that the Three Forks is a bit of a different animal than the Middle Bakken and we have a lot to learn, but we are encouraged by what we have seen so far. In general, the Three Forks interval has more variability in reservoir quality and rock mechanics than we have seen in the Middle Bakken and, as a result, geo-steering while drilling and frac design are even more critical. Of the wells that we have stimulated so far, they have generally treated at higher pressures and in wells that we have steered out of the better quality rock it has been very difficult to frac some of the stages at all.

For comparison, in Indian Hills, our 36 stage Sparrow Federal Middle Bakken well, produced approximately 35,000 boes over the first 30 days on production and the Hysted Three Forks well, about 2 miles away, produced approximately 26,000 boes over the first 30 days, granted both in a tough operating environment. So, very strong results in both zones in our 23,000 net acre concentrated block, and consistent with other wells in the area, but a bit less in the Three Forks.

We have completed our first Three Forks well in the Hebron block as well, the Wilson Federal. While we are encouraged by what we have seen, we had some challenges in completion and think that the number of stages that we effectively completed is somewhere less than 20. This is why we believe it will be very important to stay in zone in order to get all of our frac stages off effectively. The Wilson 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 off. So, still a lot to learn about the Three Forks in this particular area.

The last operations item I would 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 of consolidating in 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 in the first half of the year, a 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 are still tabulating all 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 will 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 has been a key contributor to our strategic direction and our leadership team, and this appointment is well deserved. 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 $490MM to $627MM. While the 28% increase to capital seems like a lot, we have talked about a portion of the increase in the past. We can first focus on the drilling and completions portion of the capital budget which now totals $527MM. On our last call, we discussed total CapEx likely going from $490MM to approximately $550MM, 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 have moved down the road in solidifying most of these services. In the press release issued last night, there is a breakdown of each component of our increase, with these three pieces totaling about $67MM and bringing our budget to $557MM, so this portion of the capital increase should come as no real surprise. Of this increase, approximately $19MM was due to cost creep which we talked about on our first quarter call. The additional $70MM of capital increase to our 2011 budget will really have more of an impact on 2012 and beyond. Tommy mentioned how our land group has done a great job of 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 $19MM of additional capital this year.

Other items in our E&P budget include land acquisitions, G&G, and infrastructure, which increased by $11MM, primarily due to $14MM of increase to our 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 $24MM 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 costs in 2012 and beyond.

The budget includes $6MM for a 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 future well costs. We have 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 will either grow future production or offset costs. The economics of our salt water disposal system and OWS are highly compelling, and our investment in new wells continue to bring forward the economics of our inventory. We ended the quarter with $425MM 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 $137MM 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 and our base level drilling plan. We have 8,500 barrels per day hedged 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 1^st 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 down from 12.7% differential in the 1^st quarter. The differential was positively impacted primarily by the impaired Canadian syncrude production into the U.S. which has helped to drive up the demand for Bakken sweet crude in Clearbrook and Guernsey. This is probably a short-term move, and differentials will likely widen to more normal levels once the Canadian syncrude plants get back to normal operations.

LOE came in at $8.63 per boe for the quarter, up $0.47 over the 1^st quarter. This is due to higher costs in the quarter driven by weather coupled with lower production. We still expect LOE costs will come in between $5-7 per boe for the year, albeit at the higher end of the range.

In conclusion, while the 1^st half of the year has 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 while implementing measures to reduce well costs and LOE.

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

Question and Answer Session

Operator

[Operator Instructions] Your first question comes from Dave Kistler with Simmons & Company.

David W. Kistler

Good morning, guys.

Tommy Nusz

Good morning, Dave.

David W. Kistler

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

Tommy Nusz

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

David W. Kistler

Okay.

Tommy Nusz

So it would be 800 to a million off of that.

David W. Kistler

Okay. Great. And then, 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?

Taylor Reid

So, the question is what’s the impact to rate of return with reduced well costs?

David W. 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?

Taylor Reid

So the rate of return is going to depend on the area. $1 million reduction or a ninth of total well costs is going to have a pretty significant impact. And as Tommy talked about, one of the places that makes it really compelling to us is some of the areas that are a little more marginal at lower oil prices.

Tommy Nusz

Yes, David, at lower recoveries, 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.

Tommy Nusz

5% then 15% is the highest of the high end.

Michael Lou

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

David W. Kistler

Okay, that’s very helpful. I appreciate it. And then just one last one, and I’ll let somebody else hop on. How big do you guys think about growing OWS over time? You set it up as a separate entity, clearly allows you to report it a

little differently or breakup financials differently. Is it something you anticipate growing and then eventually spinning out or am I reading too much into that?

Tommy Nusz

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 under our belt.

David W. Kistler

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

Tommy Nusz

Thanks, Dave.

Operator

Your next question comes from David Heikkinen from Tudor Pickering.

David M. Heikkinen

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

Michael Lou

Thank you.

David M. Heikkinen

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

Tommy Nusz

You know we’ve — I mean 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 calling it 30 to start just by virtue of timing and shake down. But we’ll handle some of that uptime through some 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 having more of it.

David M. 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, at 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’ve got to see how it works to get it up and running.

David M. Heikkinen

Yes. Okay. And then on the rig side, you all have had continued efficiency 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?

Tommy 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 has done really well, continuously improving our processes in spite of having basically doubling of activity.

David M. Heikkinen

Okay.

Tommy Nusz

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

David M. 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 then with 12 rigs running?

Tommy Nusz

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

David M. Heikkinen

Yes.

Tommy Nusz

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 M. Heikkinen

Okay. Thanks, guys.

Tommy Nusz

Thanks.

Operator

Your next question comes from Ron Mills with Johnson Rice.

Ronald E. Mills

Good morning, guys.

Tommy Nusz

Good morning, Ron.

Ronald E. Mills

A lot of answers on the OWS have been answered, just can you walk through 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?

Michael Lou

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

Ronald E. Mills

Right.

Michael Lou

So 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 call it 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.

Ronald E. 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 in redundancies so just what’s your overall horsepower purchase?

Taylor Reid

So the base level of horsepower purchase is about 18,000 horsepower. To frac what we need, kind of 12,000 horsepower levels so you’ve got redundancy between 12 and 18 depending on the well. And — so it will be initially eight units and eventually we’ll get to 10 but we’ve got two spare units while you’re frac-ing on the job.

Ronald E. Mills

Okay and then when you point to your production guidance, obviously your third quarter, back to normal and 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?

Tommy Nusz

I think, Michael, you can correct me, but I think the way the guys have it modeled is basically one in the second, one in the third and one in the fourth.

Michael Lou

That’s right.

Taylor Reid

Yes.

Ronald E. Mills

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

Tommy Nusz

Thanks, Ron.

Operator

Your next question comes from William Butler from Stephens.

William Butler

Good morning.

Tommy Nusz

Good morning, William.

William Butler

Also to follow-up on the frac spread when do you all expect that to arrive, the newbuild, assuming it’s a new build?

Tommy Nusz

Yes. It’s all newbuild equipment and it’ll start feathering in probably October timeframe, but there’s different cycle times 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 shake down after that.

William Butler

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

Tommy 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 was the payback period on buying that?

Tommy Nusz

Just cash on cash return on the initial investment is going to be, Michael, — I mean, that’s going to be a year.

Michael Lou

It’s going to be basically a year.

William Butler

Okay.

Michael Lou

So we went through it before 16 to 20 million of capital savings. William, and that is 7 million to 9 million of outside EBITDA, so that gets you to about $23 million to $29 million of incremental cash flow for the first full year of operations. So its right 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?

Tommy 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 but I know we’ve got some coming up. Taylor, do you want to cover that?

Taylor Reid

Yes. We participated in a number of wells that are testing, wells in both Bakken and Three Forks, so we do have some data on that front, we had planned for later this year and early next year some in-fill pilots both Bakken interwell distance and Bakken 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 to late next year at which time; we’ll be going into full down spacing and pad 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?

Tommy Nusz

Yes, hold on, we’ll tell you here in a minute. As you know, land position is moving all the time.

Taylor Reid

Well, Michael whose got the charge side of it, I can 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, maybe next year but again, right now, it’s out of our economic inventory.

Michael Lou

And it has a $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 we’ll likely let go or release. But it’s about one and half million right now.

William Butler

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

Tommy Nusz

Thanks.

Operator

From Marcus Talbert from Canaccord.

Marcus Talbert

Good morning guys.

Tommy Nusz

Good morning.

Marcus Talbert

Just following up on William’s question here and 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?

Tommy Nusz

Yes, it’s always a difficult number to forecast and you guys have heard us talk about this before. We kind of view it as having a normal land load and that run rate is — call it $20 million. We’re a little bit behind on that this year just due to how competitive it is. But as we go on, 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 ramp 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?

Tommy Nusz

The guys have modeled it out well by well. So we hedge a little bit, but it’s all thumbs up.

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?

Tommy Nusz

Yes, we’ve been running essentially at 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 crews up and running then it’s probably more like with an incremental crew, Taylor, it’s...

Taylor Reid

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

Tommy Nusz

Yes.

Marcus Talbert

Okay.

Michael Lou

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’ve got to work out some of the kinks when any of these come on, but should be going really full bore going forward through 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 this new frac sleeve technology yielding time savings by eliminating the I guess the wireline on some of the early stages. Is this a concept that you guys have tested or are there any other outside concepts that may eventually speed this up a little bit?

Tommy Nusz

Taylor may want to add to this, but we’ve played a little bit with some of the combo jobs of sleeves out on the tail, 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 these sleeve technologies 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 them with that efficiency, I think we’ll continue to be oriented that way.

Operator

Your next question comes from Marty Beskow with Northland Capital.

Marty Beskow

Guys.

Tommy 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 plan?

Tommy Nusz

Probably, Marty, 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, has dropped $16 or $17. And with that, keep in mind too that we’re given a premium to WTI as we trade at Clearbrook and Guernsey. At 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?

Tommy Nusz

Breakeven in terms of?

Marty Beskow

In terms of oil price.

Tommy 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 breakeven is somewhere around 80.

Michael Lou

And that’s all at current well cost so as Tommy mentioned if you get prolonged $80, $70, $60 oil price most likely those services cost come back down as well.

Marty Beskow

Okay. All right, thank you.

Tommy Nusz

You bet.

Operator

Your next question comes from Ron Mills.

Ron Mills

On your comments, Tommy, 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 and comparisons needed for between the Middle Bakken and the Three Forks to collect that data?

Tommy 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 well, the Hysted 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 wells. I don’t know if we’ve gotten that far yet as to coming up with a number 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?

Tommy Nusz

What do you call an exit?

Ron Mills

12/31.

Tommy Nusz

On the day? Yes. That’s probably not far off.

Ron Mills

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

Tommy Nusz

You bet.

Operator

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

Brian L. Kuzma

Hey. Good morning, guys.

Tommy Nusz

Good morning, Brian.

Brian L. 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 cutting back next year if you wanted to?

Tommy Nusz

Yes. So, I mean, it’s a couple of things. What we try 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?

Taylor Reid

Yes, three, that are over a year.

Tommy Nusz

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

Brian L. Kuzma

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

Tommy Nusz

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

Taylor Reid

So we’ve got one...

Tommy 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 they’re laddered similar to the rigs, but they’ve got flexibility to drop back.

Brian L. Kuzma

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

Operator

Your final question comes from Irene Haas from Wunderlich Securities.

Irene O. Haas

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

Tommy Nusz

Got it, I think the way the guys are looking at, it is that set the 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 we haven’t done a whole lot of it yet, other than where we’ve done those back-to-back wells where we’ll drill a 12/80 North and a 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.

Taylor Reid

Right. So we’ve been there.

Tommy 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 O. Haas

Great. Thanks.

Tommy Nusz

You bet.

Operator

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

Tommy Nusz

Okay.

Wrap Up Comments:

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