Chord Energy Corp (CHRD) 2011 Q3 法說會逐字稿

Good morning. My name is Robin, and I will be your conference operator today. At this time, I would like to welcome everyone to the Third Quarter 2011 Earnings Release and Operations Update for Oasis Petroleum. (Operator Instructions) Mr. Lou, you may begin your conference.

Thank you, Robin. Good morning, everyone. This is Michael Lou. We are reporting our third quarter ending September 30, 2011 results today, and we are delighted to have you on our call. I am joined today by Tommy Nusz, and Taylor Reid, as well as other members of the team. Please be advised that our following remarks, and 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 take these Forward-looking Statements. Please note that we expect to file our third quarter 10-Q tomorrow.

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

I will now turn the call over to Tommy.

Good morning, and thank you for joining us this morning to discuss our third quarter financial results, recent operational activity, and our outlook for the rest of the year. I will begin with an operational update and outlook and then I will turn it back over to Michael to cover financial highlights. We had a great quarter coming off the heels of two tough quarters that were largely influenced by weather. The 47% production increase quarter over quarter is a good indication that operations are getting back up to speed. As we announced in late October, we continue to grow production and our operational reports have us around 14,300 BOE per day for the full month of October. Included in that most recent production growth is about 2 million cubic feet per day of the net incremental natural gas production above the 3Q average of 2.45 million cubic feet per day, which we attribute to new wells being connected to our gas infrastructure that we will discuss more in a moment.

The team did a great job ramping up production in the third quarter to get us back on track operationally. Although we had the obvious weather related issues in the first half of the year, we have made some important strides this year in setting up our asset base for the most optimal cost efficient going forward. We have significantly de-risked our acreage position, proven the impact of 36 stage completions, and have begun understanding the full potential of the Three Forks formation. We have added two additional rigs in October taken us to 9 operated rigs, and we are ramping up our activity as planned going into 2012. So we believe 2012 will be an even better year because of the actions that we have taken during the course of this year. We continue to make progress delineating and securing our acreage position as well as consolidating in our core blocks.

Counting our core de-risked acreage, which across the basin is about 250,000 to 260,000 net acres, we have an inventory of about 1500 remaining operating locations and 2400 total gross locations. On our 9 rig program, that equates to about 17 years of inventory. As we ramp up to 10 to 12 rigs depending on the efficiency and market conditions, we would envision been able to do about 120 gross operated wells per year. So at the end of 2012, we will have about 1400 remaining locations, and approximately 12 years of inventory. Remember when we talk about our inventory, and our de-risked acreage, this is the acreage that is in the heart of the play and excludes any fringe-y stuff. All of the sub service mapping indicates that these 250,000 to 260,000 net acres look to be within our type curve ranges. Our team continues to upgrade our land position, increasing acreage on our core de-risked operated acres, and dropping acres in geologically challenged areas. We continue to focus on increasing our working interest in our operated blocks, so that each gross operated well that we bring onto production has more of an impact on our overall net production. Additionally, we estimate that this year's drilling program -- with this year's drilling program, we currently have approximately 160,000 net acres held by production. So, a little bit ahead of where we expected to be coming into the year, and a function of the great job that our land group has done consolidating acres in our core drilled blocks.

As you know, we now have nine operated rigs in the basin. We have also secured the contracts that will allow us to go to 12 rigs by the end of 2012, and potentially as early as August. At the same time, we have managed our rig contracts so that we have the flexibility to scale back to 5 or 6 rigs in a soft oil price environment. We also have 3 frack crews now, as third crew started in late June. All 3 of our crews were running efficiently in September, and all our dedicated only to us. At the end of September, we had 21 wells waiting on completion, which is down from 23 at the end of June. We brought 22 middle Bakken and Three Forks wells on production in the third quarter with an average working interest of 79%. 9 of those were brought on in September.

That brings our total operated wells brought on production this year to 46. With these wells, and the new wells we expect to bring on production in the fourth quarter, we believe we will be on the low end of our 2011 production guidance range, as we noted in late October. At the end of September, we had 4 wells that had been the fracked, but were waiting on clean out. This count grew to 9 in October as we slowed clean out activity. So our total wells waiting on completion increased from 21 to 26 in October, but we also added a third work over rig to focus on clean outs and work through our backlog. As I mentioned earlier, we had about 14,300 BOE's per day production in October, so we were still able to grow production considerably above our Q3 average.

I want to now switch gears a bit, and give you an update on our infrastructure development. On the gas side, as of November 1, we had connected 31 operated Bakken wells to gas gathering lines. A total of 29 of those were connected in the third quarter, 13 in South Cottonwood on the east side of the basin and 16 of those on the West Williston side of the basin in Red Bank and Indian Hills. As a result of the new wells coming online, daily gas production has increased almost 2 million cubic feet per day in October. We are anticipating an additional 70 to 75 wells to be connected to gas gathering infrastructure by the end of the year. So we expect to have connected approximately 100 wells in 2011.

In the first half of 2012, we expect to connect an additional 40 wells, including wells from North Cottonwood. This production all falls to the bottom line as there is minimal incremental capital cost associated with this incremental production. We have always forecasted pricing on the gas side approximately 110% to 115% of Henry Hub. Given the percent of proceeds contracts, coupled with the high BQ content of the gas, this may prove to be a little bit conservative. Something along the lines of 150% of Henry Hub might be a bit more accurate for modeling purposes. Additionally, the construction of the oil gathering infrastructure continues to make progress, and we continue to expect wells to be connected at the end of this year, and early in 2012. So far, two wells have been physically connected to the system, but have not yet made first delivery. We are anticipating connecting approximately 75 gross operated wells in Red Bank, Indian Hills and Hebron to the gathering system. Substantially all the new wells completed in these areas will be connected to that system.

The system will help us eliminate trucking costs of approximately $4 per barrel, which will immediately impact our realized prices, and will keep oil flowing through tough winter conditions, since trucks will no longer be required to pick up the oil. There is a fee associated with the production which will show up as a new line item in our financial statements. So net, net, we expect to improve our margins by approximately $1 to $2 per barrel. In addition, with the gathering system in place we will have the flexibility to nominate our oil to different delivery points along the system. We have taken steps to transfer some of the marketing responsibility in house to take advantage of this opportunity.

The saltwater disposal system we are investing in this year and next, will also be extremely valuable to overall operations. In the third quarter, our LOE was impacted by the cost to transport and dispose of water. On a per BOE basis, saltwater handling was about 28% of our cost in the first half of the year, and in Q3, saltwater handling was about 48% of our cost. This is due primarily to increased waiting times by the trucks at SWD wells, and to a lesser extent, increased cost per hour charged by trucking companies. We had this in mind when we increased our SWD budget in August to bring forward some of the 2012 capital and offset these costs. While not reflected in the third quarter numbers, we are already seeing a positive impact of our SWD system in the fourth quarter. The SWD system in the southern part of east Nesson is currently operational, and Oasis expects the SWD system in West Williston to begin operations in the first quarter of 2012 with more wells being connected throughout the year. This will eliminate the need for trucks, simplified logistics, and reduce costs in 2012 by $2 to $3 per BOE from current levels.

Now let's turn to well performance from our 36 stage completions, and the Three Forks wells that we have on production. As you know, based on our findings, we have transitioned all wells to 36 stage completions. We are encouraged by the results, and see an approximate 20% to 30% increase in production compared to nearby wells completed with 28 stages. This supports the thesis that an increase in stages continues to increase production and is a very efficient use of our capital. We continue to be encouraged by what we are seeing out at Three Forks at this stage of testing. While the geology is a bit different than the Bakken, we have some positive test results. We have now completed and brought online four wells in the Three Forks.

We have not yet discussed the results of our Spratley well, which was completed with 36 stages in South Cottonwood. The Spratley well produced 61.1 thousand barrels of oil over the last 47 days, or an average daily production of 1300 barrels of oil per day. This clearly is a good well, and we are in the process of drilling another well in the middle part of North Cottonwood to give us more Three Forks tasks on the East side of our position. We also have another Three Forks well in Indian Hills that is waiting on completion which will be close to the Hysted well that we talked about previously. As we fine tune our geosteering we believe wells in this area will produce inside the range, especially as we increase to 36 stages. As we continue to test the formation, the data we gather should further demonstrate the evolution and the upside of the play.

Finally, as we continue to push the boundaries on our acreage, we are looking forward to getting production data on our wells in our target Mondak areas. The Copper well in Montana will provide good data in our target area, as a western extension of what we've been seeing in Red Bank on the North Dakota side. Further to the south, in our West Williston position, the Bay Creek Federal well is a significant step to the south in our Mondak area. It is still early days for this 28 stage well, but the well appears to be on the low end of our type curve range. We expect to get more data over the next few quarters on Mondak, as we will drill and complete three more wells here.

One well in the northern Mondak is waiting on completion, and another well in central Mondak is drilling. The other wells should be an offset to the Bay Creek Federal. With respect to well costs, we are maintaining our estimate of approximately $8.5 million for an all sand well, and approximately $9.2 million to $9.4 for a well with ceramic and sand mix, based on our 36 stage plug and perf completions. With service cost escalation, learning in the Three Forks, and weather in the first half of the year we did see our overall average ceramic-sand combination wells more in the $9.6 million to $9.8 million range.

Going forward, well costs look to be coming back more in our $9.2 million to $9.4 million range. All that being said, we continue to look for ways to reduce our overall well cost, and it will help as we get closer to the back half of 2012, and even more so in 2013, as we start to get into more full scale mode. With that, we expect to reduce well costs by at least 10%. We are currently working on well configurations in our multi-well development paths to determine the optimum efficiency for well production and spacing. We will be testing 4 Bakken wells per spacing unit, and a six total wells including the middle Bakken and Three Forks per spacing unit early next year. Additionally, we have been testing the impact of using 100% sand in the northern portions of Red Bank and North Cottonwood. We have chosen these areas primarily due to shallower depths and lower pressures. Our original assumption was, in this environment, we would not compromise well performance by using all sand. Results today confirmed our belief that the wells would perform in line with wells with ceramic and sand mix. We are saving $500,000 to $750,000 on these 100% sand wells.

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

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

Thanks, Tommy. Before I get into the financials, I would first like to talk to you about our recent high yield debt issuance. As we've discussed before, to fund our growth profile, we were always intending to opportunistically tap the debt markets. A window opened in the high wield markets, and we prudently launched our deal to lock in a record low rates. By taking funding risk off the table, we now expect to be able to fund our capital budget outspend, given an $80 per barrel WTI oil price environment, into the middle of 2013 without tapping our revolver. Including our revolver, which was recently increased to $350 million of borrowing basic capacity, we will have about $1 billion of liquidity when the 6.5% notes close on November 10.

As Tommy mentioned we had a record third quarter with an adjusted EBITDA up $62.9 million on revenues of $88 million. Fueled by nearly 50% quarter over quarter production growth. Differentials remained strong in the third quarter as we averaged a 6.3% differential to WTI. Pricing at Clearbrook and Guernsey, our primary delivery points, were at a premium to WTI during the quarter. On another note, as you know, we also used hedging to protect our drilling program. We continue to layer in hedges opportunistically as the market warrants. We now have 8500 barrels per day, hedged for the remainder of the year, 13,500 barrels per day hedged in 2012, and 7000 barrels per day hedged in 2013. Even with a future oil price volatility similar to what we experienced in the third quarter, we feel comfortable that our drilling program is well protected, based on our attractive floor prices, which averaged around $85 to $90 per barrel of WTI.

On the cost side, Tommy discussed the impact of LOE costs and how SWD infrastructure will help alleviate these cost pressures in the future. G&A costs have trended a bit higher as we continue to grow our team to support a 12 rig program about are still in line on a dollar per BOE basis. Production taxes have also been a bit better than originally predicted. Our capital expenditures in the third quarter were $206 million, and $414 million year-to-date, out of our $627 million budget for the year. In conclusion, we have had a great quarter, and we have the right team in place to execute the increased drilling and completion activity. The team delivered traction growth, all while implementing measures to reduce well costs, LOE, and other costs as Tommy described. We also have locked in the cash and cash flow to keep extremely financially flexible in any type of commodity pricing environment, and we have matched that with our service contract flexibility. We are looking forward to a strong fourth quarter, and setting the stage for additional growth in 2012.

With that, we will turn the call over to Robin to open the lines up for questions.

(Operator Instructions) Ron Mills.

Good morning.

Good morning, Ron.

Tommy, question, you are starting to test more of the Three Forks. Any comments as to what Continental has been saying about multiple benches in the Three Forks? Or are your tests going to allow you to test multiple benches, or are you taking cores far enough or deep enough to determine the prospectivity of that to augment just the first bench of the Three Forks?

Yes, Ron, we have not done any work on that, so far. There are a few wells across the basin where we have taken cores before, but I don't think we are in a position at this point to augment anything else that's been to said about the other benches in the Three Forks across the basin. I mean, we will continue to watch what is going on there, but I don't think that we have anything to add to that.

Okay. From an activity standpoint, it sounds like you are already at 9 rigs -- and I may be reading into this, but you are already talking to people about access to rigs to go to 10 to 12 by the end of next year. On the completion side, you obviously, have the capacity with the 3 current crews, plus your own frac spread. How about the infrastructure that is going in, both east and west, in terms of its capacity to handle that ramp to 12 rigs, or are there more discussions about potential expansions there?

I think we are in good shape. Taylor, you may want to provide a little more color on that.

Yes, the infrastructures would go to 12 rigs. The basin infrastructure will be in place by the end of this year. We will add on to it, in some of the areas of North Cottonwood, for example. We are expanding the gas gathering and processing. So, that area will be covered next year. Essentially it be just expanding the gathering systems to pick up the new wells, as we drill them in each area. So, we should be in good shape with respect to the infrastructure.

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

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

Yes, that's right, Ron. We'll, obviously, will come out with a little more detail with the capital budget for 2012 later this year. As we move towards that 12 rig program next year, that's assuming that we go in that direction as well as keeping that 12 rig program flat going forward.

Okay, great. I will jump back in queue. Thank you guys.

Marty Beskow.

Good morning.

Good morning.

Hello. Based on recent well results, could you update us on your EURs as to what you are seeing and how that relates to the type curve's estimates that you've given so far, for East Nesson and also West Nesson?

So, East Nesson, as you know, on 28 stages we were estimating 350 to 600. On the west side, 400 to 700. What we are seeing based on early data is 20% to 30% uplift with 36 stages. Now, in some of the more prolific areas, say South Cottonwood, Indian Hills, some of the wells, some of the performance is a bit above the 30%. Some of the lower productive areas, the northern part of Red Bank, North Cottonwood, we would expect it to be more in the 20%, maybe a bit less than that. I think, with all those numbers, you should be able to get a pretty good sense for what the new ranges will be. At some point here in the not so distant future, we will be able to make that switch to where it will be a lot cleaner for everybody.

How about as far as for the Three Forks wells? What are you expecting, so far, from those?

At this point, it's a little bit early to tell. Obviously, we don't have a whole lot of internal data points. We've got some external data. What we have said consistently is that it is going to be a bit different. So, it may be, call it 20% less than the Middle Bakken. That being said, when you look at wells such as the Spratley well, it looks pretty consistent with the Middle Bakken, so it's going to be a bit variable. We just need to get more data.

They are all good. They are all within the tight curve bands, but we need more data. We have, obviously, talked about the 2 wells on the west side of the basin that straddle the state line over in Hebron the that are in the low end, or below the low end, of our tight curve bands for 28 stages. Those 2 wells, 1 of them effectively had 23 stages. The other 1, effectively 18 to 20 stages, but first stage recoveries looked real good. They just did not having of stages.

How about for your plans for drilling in 2012, of the gross number of wells, what percent of those do you plan on having on pad drilling? How many of those would be individual wells that you would be holding on 1280 acre units?

I don't know if we have a number for that. It's probably a fairly low percentage. It's probably, Taylor, 10%, maybe 15%?

Pad wells?

That it would be pad wells for the calendar year.

So, at least half the program is still drilling to hold acreage. Full pad wells, we are drilling out a full infill pattern is a small subset, under 10%. We will be drilling a number of just wells that have 1 well going north and 1 well going south, like we have been. That total off of pads, maybe 30% to 40%. I don't have the immediate number in that range.

So, that would include full pad development, as we call it, wells. Then, the smaller pad where we are hitting [2 x 1280-acre unit] with 1 small pad but only 1 well on each 1280-acre unit.

You said you were going to test up to 4 Bakken wells for each 1280 acre section. Is that correct?

Correct.

Up to 6 wells for the spacing unit, so does that assume that the other 2 are going to be in Three Forks?

Yes, I think the way Brett's got that laid out is in that particular pilot, 1280 pilot, it would be 3 and 3.

All right. Thank you.

You bet.

Marcus Talbert.

Hello guys, good morning.

Good morning.

Hey Tommy, you briefly touched on your inventory during the opening comments here, and you mentioned that 10 to 12 rigs would imply approximately 120 gross operated wells next year. Thinking about some of the pad drilling efforts that Taylor just mentioned, and some of these drilling efficiencies that you guys have picked up throughout the year, is there a buffer in that number for weather delays or any external factors? It just seems a little conservative, I guess.

Yes, it is. We have historically used 10 wells per rig, per year. So, with 12 rigs, that would get you to 120. Given the recent performance, we are generally --Taylor, spud to rig release about 25 days. We have had some as low 20. Then, when you count rig it moves, it is not inconceivable that you could get, if everything goes right in decent weather, that you could get 11 to 12 wells per rig, per year. Then, obviously, that improves a bit with pad drilling as well, but you're not going to see much of that in 2012. So, there could be -- the short answer is yes, it's a conservative number. There may be more upside to that. On a single small pad, where we went through 1 well north and 1 well south. The best we've done so far, rig release to spud of the next well was 12 hours. So, you start doing a lot of that and the net number could grow.

Right.

This year's average, 2011 aggregate average is 10.8 wells per rig, per year.

10.8. Okay, great.

A bit above the conservative 10 that we have been using.

Marcus, just to be clear, when we said 120 wells per year that's when you get to a full 12 rigs. Next year we will be growing into the 12 rig program, so you will have an average of, let's call it around 10.5 rigs running throughout the year. So, that 120 number for next year is actually maybe a little bit lower than that.

Right. Okay, thanks for the color there guys. You touched on the progression within Three Forks. In terms of your Bakken well results, as you move north into the Red Bank, it looks like they have been variable there. Do you know how many of these producers have been completed with more than 30 stages out of the program that you've laid out this year?

36 stage wells in Red Bank, so far this year?

Yes.

Okay, hold on. We got that. 11 wells that have been done with 36 stages. 5 of those have been on pump, so far.

Okay. Looking at some of the data for that Red Bank area, it looks like one of your strongest reducers, I think it's the Logan well, is a little bit east of where much of the activity has been there. Is there anything that you can tell from the [interval], as you move east to west. I understand that it shallows, as you move north towards Divide County, but thinking about the position as you move east of the heart of the activity there. Is there anything you're seeing different?

Generally, in Red Bank to the east and to the southeast, the results are better. So, the Logan is a good example. Another good example is the Andre well. There is also an area there where there's a little bit of a structure, so water cuts tend to be a little lower in that area. We have seen a better performance. So, as you trend to the west and more to the north and west, the water cuts tend to go up.

You are getting shallower.

Okay.

We see that pretty consistently as you start to shallow east or west, that water cuts tend to go up.

Okay. Thanks for the color. I'll get back in line here.

Perfect, thanks.

William Butler.

Good morning.

Good morning.

Thinking about where your rigs could be added in 2012 on the 9 rig program. It's 2 in the east, looks like 7 in the west. Do you have any sense, where you're going to focus those added rigs in 2012?

We are still working on the final plan, but we will add a second rig at Hebron. So, drilling in the Montana area. We will continue to run the, most likely, 2 rigs on the east. Then, that we are going to have, we talked about the infills. We are going to test some infill pilots where we are drilling anywhere from 4 to 6 wells, back to back. We will have a those pilots going on in both Indian Hills and in Red Bank. So, that will consume some of the rig time, as well.

Okay.

So, it's probably somewhere in -- if we had 12 rigs running, it's probably 8 or 9 on the west side, 3 to 4 on the east. Just depending on how the program lays out.

Okay. Then, have you done any commentary on how the fractures in place on your western versus your eastern on properties could impact spacing, or the amount of Three Forks per section you had, or is there just not enough data on that yet? Can you just talk about more about prospectivity of Three Forks east versus west?

Yes, on the east side, in the south, especially if you anchor off of the Spratley well. It looks as good as the Middle Bakken wells. Now, we will get a data point here in the not so distant future with the well that we are drilling right in the middle of Cottonwood. Then, on the west side, we still need to get some more data. We've got the Hysted, we've got the other well that is drilled but not yet completed, that's right next to it. Then, those 2 over on the state line. Again, those 2 were not completed with the high stages, so we still need to get a bit more data. But probably, Taylor, probably fair to say that it is a bit more variable on the west side than on the east. Yes, more variable, I would say at this point, the most prospective like Tommy talked about on the east side is South Cottonwood. On the west side is Indian Hills. We've got the best data there. As you go to Red Bank and Hebron, we just need more wells drilled and more tests. We're encouraged by what we have seen so far. Then, North Cottonwood, back on the east side, we have got some early wells that were drilled with short laterals, 5000 foot in 8 stage frac. So, we need to continue to step longer laterals and more frac stages to the north, which we will do.

Okay. Then, 1 last question. With the cash in the balance sheet, are there any alternative uses you all could see between now, just using that for drilling, between now and 2013? How should we think about that money?

The cash we raised is primarily for our drilling program, but obviously, gives us some flexibility if it we see good bolt on acquisitions. We've been pretty clear on that too. If we find good positions inside our drill blocks that we can operate, we will look at those opportunistically.

Okay. Would that have to come with production versus being raw acreage?

As a general rule, a lot of times, they may come with production. It's primarily acreage It's just like the deals we did at the end of last year, right? There was, I think -- out of those 2 deals, we spent $80 million. As I recall, we picked up 300 to 500 barrels a day, something like that.

Okay. Are there any -- is there are lot of deal flows still going on?

There is, but it is starting to taper off a bit. At least with things of any size.

Okay. That does it for me. Thank you.

You bet.

Dave Kistler.

Good morning, Dave.

Good morning, guys. Real quickly here, you guys mentioned on the last call, a CapEx outlook for 2012, a wide swath of $750 million to $800 million. I know you can't indicate if that has changed or bigger or higher, but can you indicate what percentage of that is that drill bit?

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

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

Yes, for next year, we are not baking much of that in just because of the percentage of wells that are in full pad. When we talk about the 10%-plus, then that's assuming that you are getting into full, big pad development mode. Not the small pads where we do 1 north, we do 1 south -- like we've been doing for the last couple of years. So, really, it's 2013 before you start doing that in any meaningful way.

Dave, just so you know, those numbers are based off of some pretty high level numbers at this point. We are going to get to our full capital program, obviously, a little bit later this year when it is approved by the Board in December, and we will come out with a little more granularity. What we were assuming there was around 75 net wells. We were just multiplying that by around that $9.2 million, on average for the wells, which gets you to your $700 million of drilling completion budget.

Perfect. That's very helpful. Then, just thinking about when you brought in the new frac crew, it took a little bit of time to get them up the learning curve and more efficient. As you bring in a new frac spread, are you guys factoring how that learning curve will take place? Or are there things that you digested and understood that you think you can drive the efficiency gains that crew faster? Any color around learnings that took place, and how you think about for moving forward and production forecast?

I will let Taylor at a little bit of color to it, but keep in mind that the 3 frac crews that we have got running for us right now, all came from outside the basin. So, we've got a pretty good bit of data on this so far.

We think that it's going to take us a little bit of time, to get the equipment and crew up and running efficiently. So, what we factor in, is say by Q2, we will be fracking our own wells, doing it efficiently. We think by -- within first quarter or very early Q2 we will be starting some fracs. We will start out doing 12 hour operations, and then ramp up to 24 hour operations to get more efficient. We have taken that same approach with some of the crews that have come in from outside the basin.

Great, that's helpful. Then just one last one, as you guys bring the marketing efforts in-house, can you talk a little bit about what that might represent in terms of cost savings, or benefit to your realizations? Then, anything that you guys are doing to make sure that you have some workarounds on this LOS, WTI spread.

I think that bring in the marketing in-house, as we have talked about, the early savings is really in the gathering system. So, eliminating trucking and being able to take our oil by pipe to delivery points. So, that will cut $1 to $2 a barrel. That will be a net benefit to us of $1 to $2 a barrel. From a marketing standpoint, what we will then be able to do is sell the third party further downstream rather than just at the wellhead. So, it does increase our flexibility and allow us to get to more markets, outside of places like Guernsey and or Clearbrook. So, we think we will have -- we will get some more attractive net backs, but we are still working through all that, David. Just -- I can't tell you how much we will have that not directly WTI based, but we will have some sold at other markets and it could be places other than LOS. It could be east coast, west coast, places that have better pricing.

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

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

That's helpful guys. I appreciate the added color there.

All right, Dave.

Andrew Coleman.

Thank you very much. I had a question on -- as you move to bring in on more of the gas wells, do you expect to see much of a change in the oil weighting for the Company in 2012?

No, it's not a big enough number really to move the needle that much on overall oil weighting. If we are at 92% oil on an equivalent basis right now, it may move it by a point, but it's not going to be meaningful.

Okay, sounds good. Then, getting your comments on the water disposal system you said, it was 48% of cost in the third quarter. How much do you think that could fall down to once you get all your disposal wells and pipes all set up?

Yes, Andrew, it's closer to 25% in the first half. I think that's an initial bogey that you get to any will continue to move costs down from there with the saltwater disposal system. It should remove quite a bit of capital costs and a lot of the increases that we saw here in the third quarter.

Okay, so target back to like the 25% range then?

Yes, 25%, and ultimately moving, probably, a little bit lower than that.

Okay. Thank you very much. Couple of easy questions.

Yes, thanks.

Jason Wangler.

Hey, good morning, guys.

Good morning, Jason.

Just on the well completion, it looks like you're getting the backlog down. What do you think in a perfect world, would you have as far as the backlog would be in the 15 to 20 range? So, is there still a little that you are working off with the 3 crews now?

Yes, I think historically what we have been talking about is that it's somewhere around 10 to 12 when you are running 7 or 8 rigs. So, when you start running 12 rigs, Taylor, that number is going to grow to high teens, maybe 16 to 18, something like that.

Okay.

Of course, it also -- we've talked a little bit about this before, but as our drilling gets more efficient, we are adding to the inventory a little bit faster than what we thought as well.

Right. Then I guess on the infrastructure, too. As you're getting all this stuff put in, as we get to year end, about how much of the production do you see will be going into pipes -- as we get to year end, when the weather starts getting really bad. So, that if we do have another bad winter what we are looking at, as far as what would still have to be trucked?

On the oil production side?

Yes.

On oil production going into pipe at year end, we think -- well, most of the wells will be hooked up by year end. Probably won't be flowing into pipe until first quarter. Which partially has to do with nominating and surety of having the wells hooked up, and be able to move that oil. So, we will have a system in place, some moving prior to year end, but I expect most of that impact to come January and into the first quarter.

Perfect. That's all I had, guys. Thank you.

You bet.

Scott Hanold. Scott, your line is open.

I'm sorry about that, I had it on mute. You mentioned 1 of the rigs that you're going to add, that is going to go over to the Hebron area. Is that because you need to capture the acreage, or you just want to just accelerate some of the activity out there?

That's more associated with continuing to extend and test some of the acreage. So, for example, we acquired [Lufts position] last year, and that was about 10,000 acres, and almost all that is held by production. But with a second rig we'll go ahead and start to drill some of that acreage. It's a little south of where we have been drilling, but we think in a good area. So, we will start drilling 1 Bakken well per spacing unit within that area next year.

That's all south of the river?

All south of the river.

Okay. Then, the Target, when does that northwestern extension well get tested in? Remind me again the least times that you have up there? How active in '12 you could be in Target?

The well that's drilled and it is actually fracked, is called a copper well, and it will be tested, probably this month. So, it is just waiting to be cleaned out. So, here hopefully in the coming weeks we will begin to test that well. In 2012, we have 3 additional wells that we will drill on Target, and those are with lease expiration, but we have a program in place that we will be able to hold all the leases there.

Then, my mistake, was there another well that you had planned in the far northwest corner or am I mistaken? Oh, you know what, that's just an open acreage plot that I am looking at here. I apologize.

Okay.

David Snow.

There's been a 1 or 2, 7000 barrel a day wells. Can you give us any ideas as to what's going on there? They are not yours, but --

Yes. So, you are referring to the Whiting well that was announced a few weeks ago? There was a 7000 barrel a day well and it was to the southeast of our Indian Hills position. So, I guess directly to these maybe a little south of Indian Hills, but in a good position. We don't have any more data on that well other than what was announced.

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

Hard to tell at this point. You are getting closer to the anticline over there, but I don't know that we have enough that data to tell us whether it to rocks or completion.

Okay. Thank you very much.

You bet.

Peter Mahon.

Good morning guys, just 2 final questions. You talked about having 160,000 acres held by production. We do see that growing to by the end of the year, and maybe by the end of 2012 even? You talked about having 250,000 to 260,000 core net acres. What percentage of that will be held by production by maybe -- the end of 2012?

Yes, so, what we have been saying earlier was that we come into the year with 90,000. We thought we would convert through this year about 60,000, but that was a little bit of high level math. What ends up happening is a you drill some of these drill blocks that, those leases will actually slop over onto an adjacent drill blocks. So, you end up capturing a bit more. So, through this year, we thought we might be at 150 at the end of this year. We are at 160 already with a couple of months of yet to go. So, probably, the end of the year is probably going to be, maybe another 5,000 acres or 10,000 acres, something like that. If you start thinking about that and you say, okay, with ramp and rig activity, next year is -- call it 70, then we are at 240. We are getting pretty close to being balanced. So, it's probably still going to be first quarter 2013 but we think we are in good shape and getting everything held.

I agree. Then piggybacking on that, you really don't see problems with the lease expiration, especially in the core areas that you're working on? It sounds like most of the core areas will be covered it before any expiration issues.

Yes, I think we are in real good shape and holding the acres that we want to hold.

Perfect, great. Thanks a lot guys.

David Deckelbaum.

Good morning, Dave.

David, your line is open.

Did we lose him?

David, your line is open.

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

No problem, David, we got you now.

Okay, maybe it's not me. I'm glad I figured that out. It back to the questions than. You talked about using 100% sands, in testing at Red Bank, North Cottonwood. Any other areas where you think that might make sense to squeeze a little bit of cost savings out or is it the risk rewards not really compelling?

Taylor may want to comment on it, but I think as you get over to the western or southwestern portion of Hebron, it may make a little bit of sense as you get down into Mondak. But maybe, those would probably be the 2 -- well the far southern part of Mondak. Those are 2 areas where it may make a little bit of sense.

I guess to put it another way, do you think we have enough data yet on the entire inventory -- or wells drilled in inventory to date that suggest that you would see a difference in EURs using at 65-35 ceramics sands mix?

In the core areas, where we are using it now?

Yes.

We do not have enough data yet. I don't think, to say -- generally, my guess is it's probably 4 or 5 years before you really could say, hey, here's what the -- I can quantify what the difference may be.

Great. Then, could you just a refresh me, quickly, as the OWS spread comes in, shall we be thinking about a differential on cost there? I know that you have to charge a third party to yourselves but would there be any cost savings from using an internal spread, not just from a per well basis?

Yes, that's at roughly $20 million -- $18 million to $20 million on an annual basis, reduction or a CapEx. As we talked about, there's 2 components of it, there's the CapEx reduction because it's just inter-Company transfer. Then, there's a component of third party as well.

I guess, lastly, just on a salt water disposal impact to lifting costs, how do we think about the timing? I know that, you've all guided a $2 to $3 decrement to the cost blended next year. Should we see that bite in pretty immediately in the first quarter of 2012? Or do you see that trending gradually over the year?

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

Great. I think that's all I had for now. Thanks guys.

Great. Thanks, David.

There are no further questions at this time.

Okay. Thanks again for everyone's participating on our call today. We appreciate all the hard work and focus on continuous improvement on the part of all the employees of Oasis and our key contractors in the office and in the field. We appreciate the support that we continue to get from our strong shareholder base. We look forward to sharing with you, in December, our capital plans for 2012 as we continue to execute on our tremendous inventory.

This does conclude today's conference call.