Chord Energy Corp (CHRD) 2011 Q2 法說會逐字稿

Good morning, my name is April. 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.

Thank you, April. Good morning, everyone. This is Michael Lou. We are reporting our second 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 Roebuck, Director of Investor Relations.

This conference call is being recorded and will be available for replay approximately 1 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, includes 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 will now turn the call over to Tommy.

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, and 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 Intercom next week and we'll have a chance to get in front of the 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 are up significantly, or 77%, from the second quarter of 2010, and up 5% from our fourth quarter 2010 production level. This is directly related to the unusual weather conditions and flooding we have experienced this year. We are all familiar with the details associated with that, so I won't cover it again.

More recently, conditions have improved significantly and we are 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 on line 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 third quarter and estimate production to come in between 11,000 BOEs 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 operating activity, we expect annual volume still to be in a full-year range of 11,000 BOEs 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 days completions, which have an average 20% to 30% greater production and [EURs] then wells completed with 28 stages. 2, the addition of our third 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 3 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 second quarter, we brought on line 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 clients' location 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've stayed relatively on that count 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 pace, we will effectively drill 1 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 about 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 waiting on completion inventory levels 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 1 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 would like to spend some time going through how we think about it.

But basically, it boils down to inventory management, cost of service, and [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 sometime, and essentially 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 rental tools and equipment.

And honestly, we likely wouldn't be able to do it were 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 crews 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 [impure] startup 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 high margin embedded 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 $800,000 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 as EBITDA in the neighborhood of about $300,000 per gross well completed. For the year, if you assume the frac crews - - the crew fracs around 30 gross wells on the 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 as we will discuss later, that means there is basically a 1-year payback on our investment in equipment of $24 million for OWS.

We're also building a facility primarily to house this operation, but we will 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 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 and the resource potential in the basin, what it's going to take 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 sometime in 2012. That being said, we will be monitoring the 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 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 7 rigs running, 6 on the west, and 1 on the east, and have contracted to pick up our eighth rig and expecting the ninth in the fourth quarter. The eighth rig will be drilling on the west and the ninth will begin working on 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 weather 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 Mondac 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 [played].

We expect the completion of the gathering and infrastructure in the fourth quarter, but some of the wells have already come online. This will add about 6 million cubic feet to 7 million cubic feet per day to our net production in 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. This all falls to the bottom line since we have no other operating cost 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 fourth 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 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 of approximately $2 to $3 a barrel. So, net-net we will improve profitability by $1to $2 per barrel. With a 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, and 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 our operating efficiencies, and 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 $15 million, up to $36 million. With this infrastructure in place, we can reduce aggregate net Company LOE by approximately $1 per barrel of oil equivalent. The benefit of this initial investment begins to show up in the fourth quarter of 2011and the incremental capital should show impact into 2012.

Now, lets 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-stage completions, and so far results look very encouraging. Based on comparison of the first 90 days of production for 3 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 2 36-stage wells produced a cumulative average of 62,000 barrels in the first 90 days, in the prior 3 28-stage wells produced a cumulative average of 44,000 over a similar time period, for a 43% uplift so far. We've 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's still early days when it comes to evaluating the Three Forks wells but we are comfortable that the oil resources is there. Early days, but we do see the Three Forks as a bit of a different animal in 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 a variability and reservoir quality and rock mechanics than we've seen in the middle Bakken. As a result, geosteering while drilling and frac design are even more critical. Though the wells that we've stimulated so far, they have generally treated at higher pressures, and then wells that we have steered out of the better quality rock, it's been very difficult to frac some of the stages at all. For comparison, in Indian Hills are 36-stage Faro Federal middle Bakken well produced approximately 35,000 BOEs over the first 30 days on production. And the [Histead] 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've completed our first Three Forks well in the Hebron as well, the [Wilson Federal]. While we are encouraged by what we've seen, we've had some challenges in completion and think 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've obtained prior to the -- 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 Intercom.

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's 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.

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 portion 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 have 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 these 3 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 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 for additional working interest 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 include land acquisitions, G&G, and infrastructure, which increased by $11 million. Primarily due to $14 million 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 $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 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've talked about this in the past, but if certain well costs become too expensive, where it make 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 saltwater 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 $425 million of cash and short-term investments on the balance sheet, which should allow us to effectively execute on our operating plans and capital investments into 2012. Additionally, we have $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 hedged for the remainder of 2011, and recently increased 2012 hedges to 11,500 barrels per day, and 2013 hedges to 4,000 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 a 6.8% differential to NYMEX, down from 12.7% differential in the first quarter.

The differential was positively impacted primarily by the impaired Canadian Syncrude production into the US, 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 into 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 costs in the quarter, driven by weather, coupled with low production. We still expect LOE costs will come in between $5 and $7 per BOE for the year, albeit at the higher end of the range.

In conclusion, while the first 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 cost and LOE. With that we'll turn the call over to April to open the lines up for questions.

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

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

Yes, so current well cost of the 36 stages, 65% ceramic, 35% sand, is [$9.2 million, $9.3 million]. So it would be $800,000 to $1 million off of that.

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 are incorporating, you would consider decelerating activity?

The question is what's the impact to rate of return to reduced well cost?

That is 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?

The rate of return is going to depend on the area. $1 million reduction, or one-ninth of total well cost 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 and lower price. Yes, and David, at lower recoveries, it's somewhere in the 5% range, and higher recoveries than that number may be closer to 10% to 15%, just uplift, on absolute percentage points, right, Michael?

Correct.

5%, and 15% at the high end.

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 5 percentage points on a pre-tax IRR basis. As you get to the higher end of the type curve range, if you were at 80% IRR on the higher side of things, at $85, it could drive you north of 100% on terms of a pre-tax IRR.

Okay. That's very helpful. I appreciate it. 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 report it a little differently, or break up the financials differently. Is it something you anticipate growing, and then eventually spinning out, or am I reading too much into that?

Yes. Probably a bit early to head down that path at this point. We will start with this one, with this spread, and see where it takes us, once we've got some real activity under our belt.

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

Thanks, David.

Your next question comes from David Heikkinen from Tudor Pickering.

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

Thank you.

Tommy, as you think about Oasis Well Services, and I'm trying to think about uptime on 1 frac fleet for the 30 or so wells, what is your expected uptime on that equipment?

If you look at it, there is what we typically talk about is 3 wells per month, per spread. So that would be 36 wells per year. We are calling it 30 to start, just by virtue of timing and shakedown. But we will handle some of that uptime through some redundancy. We know we are going to need some equipment redundancy, because this is pretty intense work for this iron. So, we will handle some of that just by having more of it.

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 backup, and spending another $24 million or so, isn't unreasonable as we think about it?

Yes, we are likely to do is, as Tommy said, start with this 1 frac fleet. Where we would like to probably get to is to cover 30% to 50% of our capacity to frac. And the idea being 30% to 50% more at high activity level, so if we do have a pull back, we will 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, and get it up and running.

Okay. And then on the rig side, you have had continued efficiency improvements as you have 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 standard that you've set now around the 7-rig program?

Yes. David, if you look at it, we've actually had a significant amount of improvement over the last year, say, since we IPOed. 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.

Okay.

So I would expect us to at least stay flat.

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

Yes, it's probably going to be somewhere in the [$750,000, maybe $800,000] range. I mean it's a bit early. There's a lot of moving parts. Obviously, if we can keep improving efficiency, we may not need 12 rigs to accomplish the same objectives. So just for scoping purposes, at this point, that's probably not a bad range.

Thanks, guys.

Thanks.

Your next question comes from Ron Mills with Johnson Rice.

Good morning, guys. A lot of answers on the OWS have been answered. Can you walk through 1 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 1 year. Is that from the combination of the cost savings plus the non-op profit margin? So you would have $1 million to $1.3 million of cost savings per well? Is that how you got to that number?

Exactly. So as Tommy mentioned, $800,000 to $1 million of savings per well. Call it 30 gross wells in the year, or 20 net. 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, call it 10 net wells, you're going to make some small profit margin there. And that's going to be around, call it $7 million to $9 million of EBITDA there.

Okay. Great. And then the $24 million that you have for this frac fleet, how are you sizing that frac fleet in terms of required horsepower and redundancies? What's your overall horsepower purchase?

So the base level of horsepower purchase is about 18,000 horsepower. For frac, we need 12,000 horsepower level, so you've got redundancy between 12 and 18, depending on the well. So it will be initially 8 units, and eventually we will get to 10. But we've got 2 spare units while you're fracking on the job.

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 north - - I know where we're expecting, but somewhere in the 17,000 barrel, 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 2012 production ramp?

I think, Michael, you can correct me, but I think the way the guys have it modeled is basically 1 in the second, 1 in the third, and 1 in the fourth.

That's right.

Okay. I will let someone else jump in. Thanks, guys.

Great. Thanks.

Your next question comes from William Butler from Stephens.

Good morning. Also to follow-up on the frac. When do you expect that to arrive, the new build? I'm assuming it is a new build?

Yes, it's all new build equipment, and it will start feathering in -- probably October timeframe. But there is 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 will be the first quarter before we are operational. And then obviously, we will have some shakedown after that.

Okay. And that will not displace 1 of the 3 you've got currently, but be added as a 4th, right?

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

Okay. And then when you ran the analysis on that, what was the pay back period on buying that?

Just cash-on-cash return on the initial investment is going to be a year.

Basically a year. Just as we went through it before, $16 million to $20 million of capital savings. And then $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 it's right around a 1-year pay back.

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

Yes. Taylor can -- the guys have been doing a bunch of work on it. We haven't done any in-field pilots yet. But I know that we've got some coming up.

We've participated in a number of wells that are testing, inner well spacing 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 interval distance and Bakken Three Forks, and we are testing a variety of distances. So we don't -- we haven't come up with the exact density that we will end up with for down spacing. We think we will have that answer by mid to late next year, at which time we will be going into full down spacing and pad drilling on our wells.

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?

We will tell you here in a minute. As you know, land position is moving all the time.

Well, Michael will have 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 the very north side of -- (inaudible) and we let some of that acreage expire in that area just due to the economics that we are 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, it would be next year. But again, right now it's out of our economic inventory.

It's 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 will likely let go, or released. It's about $1.5 million right now.

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

Thanks.

-- comes from Marcus Talbert from Canaccord.

Good morning, guys.

Good morning.

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

It's always a difficult number to forecast. And you guys have heard us talk about this before, we 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 into -- some of the guys have modeled it is probably at $20 million, at least for scoping purposes.

Okay, thanks very much. And then just looking at the production ramp in the back half of the year here, it looks like you need a sequential average of about 45% in Q3 and Q4. If I am doing the math right, and you talked 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 achieve that guidance?

Yes, the guys have modeled it out well by well, and we hedge a little bit, but it's all bottoms up.

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

Yes, we've been running essentially at 7 a month, that is 21. So that will pick up a bit. It's probably a bit more than -- once we get these frac crews up and running, then it's probably more like, an incremental crew, Taylor, it's --.

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

Okay.

What we said is that bringing on that third frac crew was 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 fairly full bore going forward through the rest of the year.

Okay. Thanks, guys. Very helpful. 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 wire line in some of the early stages. Is this a concept that you have tested, or are there any other outside concepts that may eventually speed this up a little bit?

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 berth] and the efficiency that we are able to do those jobs, I think we'll continue to be oriented that way. Keep in mind that with these -- as you continue to develop these sleeve technology, basically what you're trying to duplicate is plug and berth 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 -- probably at this point, it's probably a P-10. But if we continue to do them with that efficiency, I think we will continue to be oriented that way.

Your next question comes from Marty Beskow with Northland Capital.

Good morning, guys.

Good morning.

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

Probably, I would guess probably somewhere in the sub-$70 range for some extended period. Keep in mind that oil, just in the last 10 days, has dropped $16 or $17. And with that, keep in mind too, that we are getting a premium to WTI as we trade at Clearbrook and Guernsey. I think Clearbrook as of yesterday was about $7.50 up. So be mindful of that as well. But I think as we see some visibility that oil -- a 6 month to 12 month window would be sub-$70, I think we would have to scale back a bit.

And what do you estimate your breakeven is right now?

Break even in terms of -- ?

In terms of oil price?

I think if you were to 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, $50 to $60 range. We improve on that by having our own services, but in fairness, if oil prices are, over a prolonged period, $50 to $60 services, we'll likely adjust. We've got some of the inventory that the break over is somewhere around $80?

And that is all at current well costs. So as Tommy mentioned, if you get [purloined], $80, $70, $60 oil price, most likely those services costs come back down as well.

Okay, all right, thank you.

You bet.

Your next question comes from 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 -- what do you think it will take to do the evaluations and comparisons needed for between the middle Bakken and the Three Forks to collect that data?

I think 6 or 7 this year, Taylor. And again, keep in mind, that one of the things we talked about was variability -- if you look at the well that we just -- (inaudible) and at Indian Hills, it's pretty strong. We get over to the Hebron and 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 have gotten that far yet, as to coming up with a number exactly 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.

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 to the benefit of that third crew and going through the backlogs. But 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?

What do you call an exit?

12/31.

That's probably not far off.

Okay. Great, thank you, guys.

You bet.

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

Good morning, guys.

Good morning, Brian.

I just had a follow-up on the worst-case scenario here, given the rigs and the crews that you guys have contracted. What is the flexibility for cutting back next year? If you wanted to?

Yes, a couple of things. What we try to do is, one, we are upgrading our drilling fleet, and we think about it as -- if we can continue to run, at least in our mind, given the inventory that we have that's resilient down to those lower oil prices, call it $50 to $60, and we can continue to run 5 rigs drilling that inventory. And so we are comfortable with having long-term contracts. On 5 rigs, I think right now we've got, Taylor, 3 that are over a year. The rest of them are staged out within 12 months. So it gives us a lot of flexibility there.

And then how does it work with the pressure pump increase?

Yes, same type of thing. I think we've got 1 crew that -- .

We've got one that's a little less than 24 months now, one that's 18, and one that was 6, and those that we've worked a couple months off of each of those. So there laddered similar to the rigs. We've got flexibility to drop back.

That is perfect; that is what I needed. Thanks.

Your final question comes from Irene Haas from Wunderlich Securities.

Hi. Just 1 last question. You guys are going to go into pad drilling mode next year. I am wondering on a per-well basis once you get all of your efficiency gain and some critical mass, what would your per-well drilling and completion costs be in that particular sort of manufacturing mode in 2012?

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. 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 will drill a 1280 north and a 1280 south, and the well heads are less than 100 feet apart. And then we will frac those wells back and forth, and we were doing that latter part of last year. So we are 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.

Great, thanks.

You bet.

At this time we have no questions in the queue.

Thanks, again, for everybody's participation on 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 will be at EnerCom next week, and look forward to seeing many of you there. Thanks.

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