Chord Energy Corp (CHRD) 2011 Q4 法說會逐字稿

Good morning. My name is Rachel, and I will be your conference operator today. At this time, I would like to welcome everyone to the year-end 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. (Operator Instructions) Thank you.

Mr. Lou, you may begin your conference.

Thank you, Rachel. Good morning, everyone. We are reporting our fourth-quarter and full-year 2011 results, and providing an outlook for 2012. We are delighted to have you on our call. I'm joined today by Tommy Nusz, Taylor Reid, as well as other members of our team.

Please be advised that our following remarks, including the answers to your questions, include statements that we believe to be forward-looking statements within the meaning of the Private Securities Litigation Reform Act. These forward-looking statements are subject to risks and uncertainties that could cause actual results to be materially different from those currently anticipated. Those risks include, among others, matters 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 10-K next week.

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

I'll now turn the call over to Tommy.

Thanks, Michael. And good morning, and thank all of you for joining us this morning. I'll begin with an operational update, and will provide a 2012 outlook, and then turn it back over to Michael to cover financial highlights.

For the full-year 2011, we produced an average of 10,724 BOEs per day, more than doubling our 2010 production. And, in the fourth quarter, we grew production by 32% to 15,243 BOEs per day over the third-quarter 2011 results. We nearly doubled proved reserves in 2011, bringing total proved reserves to 78.7 million barrels of oil equivalent, of which 46% are developed. We accomplished this in a pretty tough operating environment, and our team did a great job addressing the various pressure points that arose throughout the year. It started with weather in the first half of the year, which resulted in well shut-ins, completion delays, and difficulty moving rigs and frac spreads. We ended the year with some tightness in workover and clean-out rigs, which slowed down the pace of completions.

Accordingly, our new wells brought on production were back-end loaded in the fourth quarter due to the clean-out rig constraint. We brought on 2 wells in October, 4 in November, and 11 in December. With that, our production grew from just over 14,000 BOEs per day in October, to over 16,000 BOEs per day in December. We now have 3 clean-out rigs working 24/7 jobs on our operated wells, and are looking to add a fourth and potentially a fifth clean-out rig. In January, we brought 6 wells online to first production. So far in February, we brought on another 5 wells, and have a current backlog of 26 wells waiting on completion and clean out. Of those 26, we have 10 of those wells that are fracked but waiting on clean out.

We have provided 2012 guidance of 15,000 to 16,500 BOEs per day in the first quarter, and 18,000 to 22,000 BOEs per day for the full year. Given the business risk that we've taken into consideration, such as take-away capacity, weather, and service bottlenecks, we feel comfortable with these ranges, but at a minimum in January and early February, weather has cooperated so that this is obviously helpful for operations.

During 2011, we increased our acreage by approximately 4,000 net acres, ending the year at roughly 300,000 net acres. We let approximately 5,000 acres expire in St. Croix, which is in the far north end of our East Nesson position up in Burke County. So net-net, we essentially increased our core economic acreage position by nearly 10,000 net acres. As of the end of the year, we had more than 184,000 net acres held by production, and with our current capital program we're in good shape to hold all of our core acreage before it expires.

Of our 300,000 net acres, approximately 250,000 are core derisked based on subsurface mapping and other economic wells drilled in the area. We are counting the areas that do not appear to work at $80 WTI, and are still on the fringes of delineation. At the end of 2010, as you'll recall we took all of our spacing units out of St. Croix, and at the end of 2011, we removed additional spacing units from Lower Mondac, based on more recent data from the Bay Creek Federal well. This well is looking more like the [Rebney] in St. Croix, which was below the range as we highlighted back at the end of 2010.

On the east side, just below St. Croix, on the northwest portion of North Cottonwood in Burke County, we recently completed the Peters well, which was drilled into the Middle Bakken. This was a 36-stage, all sand completion, and we're currently estimating ultimate recovery in excess of 400,000 barrels of oil for the Peters. We've had few tests in this area previously, so we're pleased with the results of this well, and it has improved our comfort with this part of North Cottonwood.

Back on the west side, our original expectation had the southeast portion of Target comparable to the western portion of Red Bank. And the well we completed there recently, called the Copper well, is coming on in-line with expectations. Based on early data, we're currently estimating ultimate recovery in excess of 400,000 barrels for the Copper well. Again, still early days, but we're encouraged by what we're seeing.

We will continue to drill Middle Bakken wells in our extension areas, specifically northern Mondac, Missouri and Target, and throughout 2012, we have plans to drill about a dozen wells in these areas. We've also been further testing the Three Forks opportunity across our entire acreage position. We discussed the Spratley well on our last call, which is a Three Forks well in the lower portion of South Cottonwood. This well continues to perform well, and has produced 71,000 barrels of oil and 113,000 barrels of oil over the first 60 and 120 days, respectively. The Spratley, in fact, is one of our best wells to-date.

Further north, around the middle section of South Cottonwood up in Township 156 North, we have the Caspian Three Forks well that has produced 32,000 barrels in the first 60 days. Still early days for this well, but we're encouraged by its performance as well. In our primary inventory for East Nesson, we have included 3 Three Forks wells per spacing unit around these wells based on performance of the Spratley and the Caspian. In 2012, we plan to continue to complete some additional Three Forks tests in the Cottonwood area by moving further north one step at a time. But we clearly feel like a good portion of our position there, or about 14,000 net acres, is delineated for the Three Forks.

On the west side, we have 2 Three Forks wells in Indian Hills, the Hysted and the [AndersMadson]. The Hysted has produced 34,000 and 52,000 barrels in the first 60 and 120 days on production, while the AndersMadson has produced 29,000 barrels over the first 60 days. Based on results from these wells, we've included 3 Three Forks wells per spacing unit for our primary inventory, and most [are blocks] inside Indian Hills.

In Hebron, more recent data from the Moore well, which was one of our original Three Forks tests right along the state line, indicates that this well is performing better than we originally expected. Given that this well was set up for 28 stages, but ended up with only about 23 stages effectively completed, this is very encouraging. Again, we are currently estimating ultimate recovery in excess of 400,000 barrels for the Moore well.

The last comment I'll make on growth catalysts is around the work that we're doing on well configurations on multi-well development pads to determine the optimal efficiency for well production and spacing. We have started drilling our pilot project to 4 Middle Bakken wells and a spacing unit in Indian Hills, and have another planned for Red Bank. We have a 6-well test in Indian Hills that will include 3 Bakken wells and 3 Three Forks wells, and a single spacing unit. We also will be doing a 3 Bakken well test in Red Bank, and we have another 15 pilot projects where we will be testing infill spacing.

We're placing a varied array to gather some microseismic data that will cover a 6-well pilot project in North Indian Hills. We will be measuring frac performance, and look forward to gathering additional data through our tests this year. Needless to say, we have a lot going on, and the team is excited about all of the catalysts we have in 2012, and the transition we will be making from acreage capture to development mode as we exit the year.

Having higher working interest in our drillable blocks allows us to capture more of the benefits of this work, and throughout 2011 we've been able to increase our average working interest in our operated drill blocks to 70%, from 63% at the end of 2010, driven largely by acreage swaps. As a result, each gross well we bring online has greater impact to overall net production. Since each gross operated well requires the same level of resources in the field, increased working interest leverages our efforts and success across more net wells. So, year-over-year, even with the reduction in drill blocks in Lower Mondac, we still increased net operated spacing units by 1 up to 171 out of our 194 net total spacing units.

At the end of 2011, we had a total primary and potential inventory of 2,254 gross locations, and 1,345 gross operated locations. Assuming we are drilling 108 projects in 2012, and approximately 120 projects per year thereafter, we have more than 11 years of operating inventory locations remaining.

Switching gears a bit, I'm sure you're all well aware of the differential swings of Bakken crude at Clear Brook and Guernsey relative to WTI. In 2011, the average differential at those hubs ranged from $6 below WTI to more than $8 above. In January, the differential hovered between $3.50 and $6 below WTI. Recently, however, the differential was below WTI by more than $20 for 6 days, but it came back to about $7.50 on February 15. And as of yesterday, the differential was about $13. So, it continues to be pretty volatile here.

We now have a company within Oasis called Oasis Petroleum Marketing, or OPM, which provides marketing services for us. OPM has been working to mitigate some of the take-away capacity risk through a third-party pipeline gathering system that connects to numerous transport pipes and rail facilities. This will allow us to begin transporting crude oil from the wellhead, which will eliminate the need for trucks, and will give us flexibility to nominate our barrels where it makes the most sense. This gathering system is expected to be fully operational with access to delivery points by the end of the first quarter or early second quarter. We currently have 49 operated wells that are mechanically connected, and have scheduled an additional 38 wells to be connected. Once operational, we will have approximately two-thirds of our total net oil production on pipe.

We estimate that our differential will improve by $4 a barrel by eliminating the cost of trucking for the barrels that are on the gathering system. There will be a $2 per barrel offset cost associated with the pipeline delivery method. The transportation and gathering expense line will be an addition to our financial statements as we move through 2012, and we've provided guidance along those lines of $1 to $1.50 per BOE for 2012.

While on the topic of infrastructure, we have connected 75% of our current wells to gas infrastructure, and expect another 46 wells to be connected by the end of the third quarter. On our last call, we had 31 wells connected on the gas side. Currently, as of February 1, we had 128 connected to gas infrastructure. The impact of gas production has been significant as a result. In the first half of February, we averaged net 8.7 million cubic feet per day, compared to a December average net of 6.3 million a day. Gross operated gas volume has grown from around 2 million a day at the end of August 2011, to currently around 15 million cubic feet per day.

So, we've made significant progress over the last few months. While natural gas prices have been sub-$3 per MMBtu, we realized $7.86 per Mcf in the fourth quarter due to our liquids rich gas production. Because of our percent of proceeds contracts with third-party gathering and processing companies, this incremental gas revenue dropped straight to the bottom line.

The third component of our infrastructure is our saltwater disposal systems, from which we're beginning to see LOE reduction benefits. Our LOE per BOE decreased $0.60 or 7% in the fourth quarter, partly due to the SWD systems coming online. More importantly, however, is the impact that it's expected to have during inclement weather conditions. The SWD systems will allow us to maintain production even if roads close, since we're reducing the need to truck water. As we mentioned, we have budgeted approximately $57 million for infrastructure in 2012, with most of that capital directed to our SWD systems.

By the end of 2012, we anticipate 80% of our operated drill blocks will be connected to a pipe system to dispose of saltwater within Indian Hills, Red Bank, Hebron, North Cottonwood, and South Cottonwood. We've guided LOE to go from $8.70 in 2011, to $6 to $8 per BOE in 2012. We expect to start the year at the top end of the range, and move down throughout the year.

To give you an update on Oasis Well Services, we have accepted delivery of much of the equipment, and have already completed some pressure tests and have pumped our first revenue job. We plan on fracking our first well in late March, and intend to run with a daytime crew in the second quarter, and have full 24/7 operations by late second quarter or early third quarter. We continue to expect to save $10 million to $12 million in 2012, and those savings are included in our $758 million drilling and completion budget.

In addition to OWS, we have 3 frac spreads already under contract, and the total should keep us pretty much balanced with our rig program through 2012. We have 9 rigs running now, and have 3 additional rigs under contract to be delivered this year, one at the end of the first quarter, one at the end of the second, and one during the third quarter. With this program, we're planning on spudding 108 gross operated wells, which equates to 74 net operated wells this year.

In our 2012 drilling budget, we essentially have used $10 million per well for our cost. We continually look for ways to reduce overall well costs, and expect that as we get closer to the end of 2012, and even more so into 2013. As we get more into full-scale pad development mode, we expect to reduce costs by at least 10%. As we've discussed, we continue to see solid performance in the wells where we've pumped 100% sand in the northern portions of Red Bank and North Cottonwood where it's shallower. We're saving approximately $500,000 to $750,000 on these 100% sand wells.

In general, we feel that well costs are at the top or close to the top at this point. While no service company has come to us so far and offered meaningful discounts to current pricing levels to attract our business, we have seen more stability in pricing, and additional availability and options. And we're seeing some operators moderate activity as a function of well costs.

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

Thanks, Tommy. 2011 was definitely an exciting year for Oasis. We were able to overcome weather challenges, and execute on our drilling plan, build out our team, effectively capitalize our business, and lay a strong foundation for 2012 and beyond. For the year, we had adjusted EBITDA of close to $235 million. We exited the year with $491 million of cash on the balance sheet. Combining this with our revolver availability, as of year-end we had over $800 million of liquidity available to invest in the business in 2012. In the fourth quarter, we had record adjusted EBITDA of $85.9 million, an increase of 36% over the third quarter, driven largely by production growth. Differentials remained strong, but we're ticking up towards the end of the quarter, and we're about 10%.

On the cost side, Tommy discussed the impact of LOE costs, and how SWD infrastructure will make a meaningful contribution in 2012 and beyond. G&A costs have trended up as we've staffed up the team to execute on a larger drilling program, but we are beginning to trend down on a dollar-per-BOE basis. Production taxes for the year were approximately 10.25% of revenue, which is a bit better than originally projected. To close out, our capital expenditures were $250 million in the fourth quarter, and just under $670 million for the year.

We are excited about the future ahead. We have a strong balance sheet, a great team, and the right assets to drive growth and shareholder value.

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

(Operator Instructions)

Your first question comes from David Kistler with Simmons and Company.

Good morning, guys.

Good morning, Dave.

Real quickly, you highlighted that well performance has been a little bit better and weather's been a tad better. But with the backlog of about 26 drilled uncompleted wells, can you talk a little bit about what's necessary as far as bringing that down, in order to maintain, or not maintain, but achieve, your Q1 production guidance?

Yes, what I would tell you, Dave, is, we talked about earlier on the call, we tried to include all of the business risks in the guidance that we gave and that includes things like this well backlog. We've known about that. So there's the well backlog. There's weather, which has actually been pretty kind to us so far, take away and a number of things, so we try to incorporate all those things into the business risk that we roll into that guidance. So having 26 wells doesn't impact our view of guidance for the first quarter or for the full year.

Okay, that's helpful. And thinking about, let's call it 40%, of that being associated with waiting for additional clean out rigs or work over rigs, and looking at the vertical integration plans with Oasis Well Services, is that ever something you'd look at adding to the fleet on the vertical integration side?

We're not currently looking at that but I'd never say never.

Okay, that's helpful. And then maybe to just think about potential locations a little bit, you talked about some of the fringe areas and better well results there. Saw a nice uptick in the primary locations, but what will you need to see in these fringe areas to potentially, or to take up these potential locations as well?

Taylor, you want to pick that up?

Yes. So in the fringe areas, if we continue to get results like we just talked about in target being over 400,000 barrels, that range as we drill out into those areas, then we'll start incorporating it into inventory.

The other thing that'll help us is, all the work that we're doing now on infill spacing and the number of wells per spacing unit. Because we from the very beginning continue to stay at three and three for Middle Bakken and Three Forks, so we're going to get a lot of data on that this year.

Okay, that's very helpful. I'll let somebody else jump on. Thanks so much, guys.

Thanks, Dave.

Your next question comes from Scott Hanold of RBC.

Good morning, guys.

Good morning, Scott.

Quickly, and I'm sorry, Tommy, I missed some of that when you were going through it. But what was production again in December? And did you mention what it was in January, what it currently is running at?

We didn't on January. For December it was 16,200 from 14,000, when we came -- October, so as we came out of the quarter, 14,000 and as we exited in December, we were at 16,200.

Okay, so what does that look like right around now? Can I ask you what your current rate is?

We've been roughly flat with December but still bouncing around a bit and a lot of it's operational numbers that we have at this point. We haven't flowed all that through the financial system, so I hesitate to give you a firm number, given that we don't have PPAs and inventory changes and all those things on our numbers at this point.

Okay, okay. So, that's fair enough. And as you guys look forward into 2012, it seems like you going to have several areas where you're going to see some cost savings, and obviously, having your own frac services group helped that. Is there any plans to add another frac spread? Or are you content with what you've set out at this point in time?

Scott, what we've said consistently is that running one frac spread is probably not on the edge of the efficient frontier. If we had two, we could continue to run two crews along with five or six rigs in a low price environment. So, I think two is probably the max for us as we see it at this point.

But being able to run two is going to make us more efficient, But we'd like to, before we make a hard call on that, get a few frac jobs under our belt. So, we've got a little bit of time before we figure out whether that makes a whole lot of sense.

So, would that be like a back half of '12 thing? Is that reasonable to think about that way?

That would likely be in the '13, and once we make the decision, I mean the big question there will be once we make a decision on that, if we assume to go forward, it would be the cycle time on delivery of equipment, which should be getting better than what it was last year.

Okay, got it. And on the acreage front, it sounds like you've increased your working interest in some of your more core areas, and as you go through over the next few years, call it, as you continue the development process, what's the plan on the acreage position? Are you guys going to continue to be pretty opportunistic on some bigger tracks or are you just looking at bolting on to some of the existing working interest right now?

Both. We've been very successful on the swap front. We've been somewhat successful on picking up bits and pieces in our core areas but as a practical matter, there just isn't a whole lot left out there, within our core blocks. And then we continue to look at bolt-on deals. In 2011, we just weren't successful at any of the deals that we looked at.

Is it more of a pricing? Did pricing just get too competitive in the basin?

For us, last year it was more service driven. Because if we pick up something then we've got to execute on it. In order to execute on it, we've got to have the services. So we've either got to get the services on the open market which you know has been extremely tight, or we end up cannibalizing our existing asset position. And so that does, irrespective of value, that does adjust our views a bit with respect to what we're willing to pay for things.

Okay. That makes a lot of sense. Thanks, guys.

Your next question comes from Michael Hall with Robert W. Baird.

Thanks, good morning.

Good morning.

Just kind of curious, a little bit more on the commentary around the fringe tests. What's the inventory exposure there, if you do continue to have success, the upside potential? And then, is there any plans or what do you need to see to start testing Three Forks, as well as the Bakken?

So, just to back up a little bit on the inventory, when we're talking about the fringe areas, in the Bakken, most of that is included in inventory currently. So, even when you talk about Luft and Missouri, which are a part of Hebron, out far to the west in Montana, it's actually in the overall inventory numbers at three Bakken wells per spacing unit.

As we step out and drill into those areas and confirm it, we look at it as confirming that inventory. The way we approach it is, when we have drilled a well such as St. Croix or in Lower Mondac that Tommy talked about, we'll actually extract that inventory and take it out of our numbers. So, there is still some speculative number of locations. But by the end of this year, you'll pretty much have, at least in the Bakken, either confirmed all that Bakken inventory or eliminated it, if it looks like it's below the economic threshold at $80.

Okay. And then how about Three Forks test? Any plans or thoughts around that, in those fringe areas?

So the Three Forks test that we've got planned for this year, there is at least one additional well in Hebron in Montana. Most likely, we'll have at least two additional wells in Red Bank, We've got a number of additional wells in Indian Hills. But we've already confirmed that area with respect to Three Forks. And then over on the East side, the furthest north well that we have in the Three Forks is the Caspian, which is about half way up, our total drill block --

That's 156.

Yes, 156. And we will continue to step north with Three Forks test, and we have at least two planned to the north this year.

Okay, that's helpful. And then, last one for me would just be, have you put out a 2012 exit rate type goal or targets? Or do you care to?

I have not at this point, Michael. Okay. Fair enough. Thanks guys. Thanks.

Your next question comes from Ron Mills with Johnson Rice.

Good morning.

Good morning, Ron.

A couple questions. Continent, in their release, their call earlier, talked about incremental Three Forks benches. Have you participated with them as a non-op in any of those wells? Or are you seeing same opportunity on some of your acreage, just as you look to increase your Three Forks testing this year?

Have not at this point. Some of that's been along the Nesson. There was one that was about six miles east of Indian Hills. We have not participated in any of those. We continue to monitor their activity and we haven't done any testing internally on that at this point, so it's still early days.

Okay, and on the OWS side, have you walked through or can you give us at least a 30,000-foot view of the background of the team that you brought on, in terms of experiences, as you look to start up the 12-hours operations within the next month or so?

I'll start and then Taylor can give you some color. One of the things that gave us a lot of comfort with starting down that path was the amount of internal expertise we had on that side of the Business. Within our office, and this is dated so this is back when we were making that decision, so six months or nine months ago, we had over 100 years of stimulation or pumping services experience just in our Williston office.

And because of that, that's one of the things that really gave us -- and some of those guys have actually been part of start-up operations for some of the other service providers. So that's part of what gave us comfort in starting down this path. And then of course, we've supplemented that. We're up to just under 20 people, I think, now. We didn't want to hire a bunch of people in advance of the equipment being there and having them sit around doing nothing. So we are staging the people along with delivery of the equipment. So, I feel pretty good about the in-house expertise that we've got in the Williston office and their ability to execute.

You want to add anything to that?

The only addition is, we'll probably be around mid-20s when we start people pumping, in terms of total employees. We start pumping the 12-hour jobs and then obviously we'll build that up to get to the 24-hour jobs, to more like 50+, 50 to 60 employees.

Okay, and just mechanically on the price differentials, Michael, you had the big blowout for plus or minus a weak period there. How is your oil out there priced? Is it priced 30 or 40 days out? Were you in the middle of pricing oil during the disconnect and I'm just trying to get a sense as to January, February oil probably wasn't impacted. But because it was such a short duration, where it was a $20+ type differential, are you forecasting much of an impact on your realizations?

Yes, Ron. As you mentioned, we do price out our volumes in advance and so usually some time around the middle of the month, you've got prices for the following month. So where we'll see an impact is probably more in March. And what we've said historically is in a tighter market like we're in, it's probably going to be closer to the 12% to 15% discount March yield, because of the extreme volatility you saw here in February. Probably going to be a little bit wide of that. Historically, we've seen up to 18% so you might see something like that in the March time frame.

But on a blended basis, you'll have your January and February was better, given the differentials, but so on a blended basis you're 11% to 15% range for the full year? You still remain comfortable with that?

Yes, the first quarter's probably going to be on the upper end of the 12% to 15% range most likely. But that's where we see the year being 12% to 15%. As we get closer to the end of the year with a lot of the rail capacity coming on, it should improve the differentials.

Okay, and then one last one. I know you've mentioned in the past about having a couple guys looking at other areas. Are you still looking at other areas, still domestic versus international? Or are you really mostly chewing on what you have in the Williston?

At this point, Ron, I would say it's the latter. What we're trying to do is get a team in place that's segregated. What happens currently is, like last year, I think we looked at, I don't know, 15 or 16 deals that were bolt-on deals but what we end up doing is cannibalizing the rest of the organization to get all that stuff evaluated.

So, we're trying to pull together a separate team that starts to evaluate those things, and starting with in and around our core positions, Williston expansion, other tight or unconventional oil things, in that order. While we have a significant amount of international experience, at this point that's pretty far down the road for us, I would think.

Perfect. Okay, great. Thank you guys.

Thanks, Ron.

Your next question comes from Irene Haas with Wunderlich Securities.

Thanks, all my questions been answered.

Okay, Irene, thanks.

Your next question comes from Jessica Chipman with Tudor Pickering Holt.

Good morning guys.

Good morning.

Just a couple quick questions, I might have missed this, but in your discussion on the fringier areas--

You're not coming through.

Can you hear me now?

Yes.

Okay. We just got new phones and they might be a little difficult to hear me. Just a question on the fringier areas. I'm not sure if you'd mentioned this, but what well costs are currently at Target?

So the well cost in an area like Target, we're still working on where you may end up is pumping all sand in an area like that, so you're going to significantly reduce the well costs. You'll probably be closer to $9 million or sub $9 million.

And as Tommy said, we're continuing to work through the savings that we expect to see those you project forward to the end of this year and into '13, going more to pad drilling operations with those efficiencies. There's savings on top of that. So, don't have an exact number for you, but it's sub $9 million and working down from there.

It's probably fair to say that at this point, as we expand out of the core part of Hebron into across south across the river and then further to the west, it's still going to be the higher well cost of the $10 million range. North Mondac's probably the same. Target will probably be more all sand. It would be more in the $9 million range.

Okay, thank you. And then just I was thinking about the $500,000 to $750,000 savings per well for using all sand. You talked before about what the incremental hit to EUR that you measure internally.

For using all sand?

Exactly.

It's not, we're getting the same results with well that's all sand in those areas as we do pumping ceramic.

At least early time data, that's what we're seeing.

It's shallower so the closer pressures are not as high. So, we don't think there's sand profit degradation that impacts the EURs.

Okay. And then, I hate to harp on this, because I know it's a near-term issue, but just thinking about differentials a little bit more, as far as Oasis on the marketing side, just clarifying, about two-thirds of current oil volumes will be covered by Banner pipeline going forward. Are there incremental pipeline projects or other things in the queue that you think will help get oil out of the area?

So, right now the Banner system will cover the three main areas we're drilling on the west side, Jessica. So, it's the Hebron area, Red Bank, and it will extend a little bit into Target as we drill wells there and cover Indian Hills as well. So, where we don't have infrastructure yet is on the east side, and so, we're starting to work on that but we don't have anything in place there yet.

Okay, thank you.

Thanks.

Your next question comes from Dave Camp with Raymond James.

Hi, guys.

Good morning, Dave.

Earlier this week in San Francisco, Intercom had a services seminar, and one of the subjects was oil take away, treating, and tracking. You want to talk about the water tracking and all of those, that subject?

I'm not sure exactly that we're following you on the tracking.

Let me restate it. Is water a problem? And do you anticipate any new regulations on water handling off fracking?

So water hasn't been a problem, either in terms of source water to frac the wells or in terms of disposal. We've had periods for example, July or August time frame last summer, where disposal capacity got tight and the costs of disposal got pretty high.

But we've continued to expand our SWD infrastructure projects and so we now have saltwater disposal wells in all of our major producing areas and operational pipelines, as well that will take water from the producing wells to our disposal wells. And we continue to expand that. We'll do that for the rest of this year.

Do you have a feel for what your cost per barrel is in water disposal and handling?

So without the disposal systems, it's $3 to $4 barrel to dispose of produced water. With the systems in place, you cut that by depending on the area $1.50 or $2 a barrel or some instances more.

Good. Thank you.

You bet.

Your next question comes from David Snow with Energy Equities.

Yes, hi. You had referred to your down spacing pilot. The last we heard from Brigham is that they were doing four per 1,280 and were going to experiment to see if they could get five per 1,280. Do you have any idea from the field as to whether that research got done before the new people took over? Or whether it got done by the new people and any feedback as to how that may look?

I'll let the guys chime in here. I know they did a four-well pilot up in the Olson area. But I don't know that they've actually put in the five-well pilot at this point that we're aware of. Have you guys?

We don't have access to data.

Okay, and I think they reported the four-well worked pretty well without any interference. And I'm wondering, you guys have been pretty timid on increasing the density. Do you see yourselves trying to put four for 1,280 in a pilot?

Yes, what I would tell you, David is that I don't know that it's so much being timid about moving forward. It's more a function of us focusing on a rig activity holding our drill blocks. That was Job One and now we've reached a point to where we've got that under control and we can start testing all of these pilot concepts. And in fact, we've got the one in process right now in Indian Hills of going to four wells, so I think we're in pretty good shape there.

Okay. Do you see any possibility that it'll go to five wells before said and done?

Boy, I think it's a little bit early to make that call. We'll go to four and see what we see, and then try to approach it from one direction and not overshoot, I guess is the way we approach that.

Okay.

The last thing we want to do is go overcapitalize a bunch of drill blocks.

I hear you. Okay. Thank you very much.

You bet.

Your next question comes from Jason Wangler with SunTrust.

Good morning, guys.

Good morning, Jason.

Just a little bit more on the timing I guess, the OWM. As you get that ramped up, just curious right now, you talked about where your oil gets nominated to. Is it pretty much just Wyoming and Minnesota? And as you get that ramped up, are you going to look to send more down toward the Gulf or at least some other areas that are hopefully a little bit better, pricing-wise?

So, we've got a fairly distributed approach, and we have a combination of pipeline and rail, and so what we'll try to do is continue to keep a pretty diversified approach there. We're not going to put all of our eggs in one basket and try to go to what might be the best differential today because that can very quickly change, as we've seen over the last 6 to 12 months.

Yes, that makes sense. And then just one other one, if I could. On the OWS, as far as sand it's been a problem up in the area getting sand and all over, do you guys have contracts to be able to grab sand? Or what's the opportunity you have there as far as making sure enough supply?

So, we have a few sand sources. We do have a contract with one party that will deliver sand, but we also have the ability to buy from other sources on spot market.

That's all I had. Thank you guys.

You bet. Thanks, Jason.

Your next question comes from Peter Mahon with Dougherty & Company.

Good morning, guys. Just had one question.

Okay.

This has to do with your overall thoughts on future development, with volatility and differentials and well costs being north of $10 million, a well. How do you guys think about just the rate of development, and at what levels we should think about altering that rate of development? I know some of the other E&P companies have elected to maybe accelerate development in other basins or plays due to some these economics. How do you guys think about that?

What I would tell you is, as we come into this year, as we develop our plan both for the 2012 year and the five-year we look at a number of scenarios. But one of those is an economically constrained case, and I think as you've seen with some of the other operators, as you start to get well costs that approach and exceed $11 million, then you will continue to see people, including us, change their behaviors.

So far, our guys have done a great job executing and we've been able to keep our well costs for 36-stage, plug and perf, 65/35 ceramic and sand mix, keep that well cost around $10 million. But like I say, if you start seeing that get up to plus 10%, then you'll see us start to change.

But given where we see services now, we don't see service companies coming at us offering big discounts but availability has certainly improved. As we go out to look for services, there are options available to us at current prices. So it looks like it has moderated a bit. But it's something that we're mindful of and if it makes sense to ramp back, given economic conditions, then we'll do that.

Okay, great. Thanks a lot.

You bet.

Your next question comes from Robert Carl with CSCM.

Hi, guys. Great quarter. Think of a concept of a generic Bakken well drilled to, say, the Middle Bakken and you've got a couple years experience now. What type of production curves are you seeing on these things? A generic well, if there's such a thing?

Yes, so there's a couple of things I'll say on that is, our type curve is we're at 76% initial decline, a B-factor of 1.6, and a terminal decline of about 6%. And generally that works for a bulk of the well population. What we see is as you get into some of these higher rate areas, you can't necessarily just take that same curve and bump it up.

That initial decline will be a little bit steeper. So call it 82% initial decline with a similar B-factor and terminal decline. And some of the lower productivity areas, and where you get higher water cuts, what we'll see is that, that early time data will be a bit muted. So, the initial curve that I gave you will work for probably 60% to 70%, or probably 60% of the wells, and then you have probably 20% of the wells that are the high productive ones, and 20% on the other side where that initial part of the curve gets a bit muted, so they look a lot flatter.

Right, yes. Okay, well that answers my question. Thank you very much.

You bet.

Your next question comes from Andrew Coleman with Raymond James.

Thanks a lot and good morning, folks.

Good morning, Andrew.

I had a couple of questions. Just thinking about the AFEs for the $10 million, how much of that is baked in for water disposal? How much is baked in for building the facilities out to the well site, pipelines and that?

The $10 million is well cost, and then we've got the $57 million of infrastructure capital for this year that accounts for the gathering system work.

Okay, as I try to get a sense from as you move from holding the acreage to down spacing, what potential for cost reductions are in the system?

Yes. So far, we've been calling it 10% but before we move off of that or get it anymore aggressive, we'd sure like to get some better data, which we will have as we do all of this pilot work this year.

Okay. And then, thinking about the B-factor of 1.6, is that -- when do you put the well on pump and does that factor into the 1.6?

Yes, that includes the well being on pump.

Okay. All right, great. Thank you.

At this time there are no further questions. I'd like to turn the call back over to Mr. Lou for any closing comments.

Yes, this is Tommy. 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 of the employees at Oasis, both in the office here in Houston and in the field up in Williston. We appreciate the support that we continue to get from our strong shareholder base. Thanks again and have a great day.

Thank you, ladies and gentlemen, for participating in today's conference. You may all now disconnect.