Chord Energy Corporation (CHRD) Q3 2012 Earnings Report, Transcript and Summary

Good morning. My name is Brandace, and I will be your conference operator today. At this time, I would like to welcome everyone to the Third Quarter 2012 Earnings Release and Operations Update for Oasis Petroleum. [Operator Instructions] I would now like to turn the call over to Michael Lou, Oasis Petroleum's CFO, to begin the conference. Thank you. Mr. Lou, you may begin your conference.

Thank you, Brandace. Good morning, everyone. This is Michael Lou. We're reporting our third quarter 2012 results, and we're delighted to have you on our call. I'm joined today by Tommy Nusz and Taylor Reid, as well as other members of the team. Please be advised that our 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 disclosed in our earnings release and conference call. Those risks include, among others, matters that we have described in our earnings release, as well as in our filings with the Securities & 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 third quarter 10-Q today. 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.

Good morning. We'll follow a similar format to what we've done in the past, where I'll cover some introductory comments, Taylor follows with more operational color and Michael will finish with a few financial highlights. We've had a tremendous year thus far. When we entered the year, our senior leadership team sat down to identify strategic risks and opportunities that we would be facing in the near term and over the long term. We had a broad dialogue covering extremely important topics like safety, attracting the right people, building our culture as we grow, capital discipline, oil price and movement and cost control. I'm going to highlight a couple of key accomplishments that are tied, in some measure, to this strategic process. At the same time, understand we approach all of these topics with a focus on safety, and we continue to emphasize this with our employees, contractors and partners to maintain safe worksites across the basin. First, drilling and completion costs had increased dramatically throughout 2011, and we knew it was time to proactively find ways to cut costs or consider slowing down our drilling activity. Even in early 2012, well cost continued to increase, largely due to continued service cost creep and, in part, due to some proactive regulatory changes enacted by the NDIC. Average well cost plateau-ed in the first half of the year at approximately $10.5 million per well, which was approaching a critical threshold that you've heard us talk about, at about $11 million per well. With the initial focus that the team placed on controlling costs, we were one of the first players in the basin to force our costs to roll over and start heading down. On our last call in August, we spoke about driving our cost down to $8.8 million by the end of the year. While our operations team over-delivered and has already met the year-end target, our wells now, on average, cost $8.8 million to drill and complete, and that's not including the benefit of Oasis Well Services. Just looking at our operated, drilling and completion capital in the third quarter, OWS was able to reduce our average well cost across our entire operating program by about $300,000 per well, driving our weighted average well cost to $9 million for the quarter. Going forward, we do not believe that $8.8 million is the floor, as the team continue to find ways to be more efficient and optimize well completion designs. Just adding the incremental 5% to 10% savings for multiple wells drilled on pads next year, we believe we can get cost to $8.5 million or less. Great job by our entire team coming up with such an impactful plan and then executing on it. Saving $2 million per well from $10.5 million down to $8.5 million is massively accretive to our NAV and our cash flows. In addition, with OWS, we've executed on our plan that we laid out 2 years ago, with results exceeding our original expectations supplementing our cost control efforts. Second, the team is focused -- has been focused on moving oil and maximizing oil price realizations. Our internal marketing group, which we call OPM, has done a great job making sure that we move all of our oil that we are producing, which is 93% of our overall net oil production. Our gross operating crude volumes have doubled from the third quarter of 2011 to the third quarter of 2012, up to over 30,000 barrels per day in the third quarter. And our marketing team has ensured that these barrels find their way out of the basin, whether by rail or by pipe, at the best price. Their efforts have allowed us to deliver some of the best differentials in the basin, even when you add the marketing and transportation cost of $1.23 per BOE to our differentials. We continue to have about 60% of our oil on the infield gathering system and expect this to increase to over 80% in the first quarter of 2013, as we get most of our East Nesson wells connected to the new gathering system being built there currently. This system, which is being built by Highland, will be connected to the existing system so we will have marketing flexibly on even more of our volumes with multiple outlets, including 6 rail loading facilities and 4 pipeline connections. In conjunction with physically moving our barrels, we have an aggressive hedge program to protect us financially as we outspend cash flow in the near term. We now have 20,000 barrels per day hedged in the remainder of 2012; about 18,750 barrels per day hedged in 2013; and another 5,000 barrels per day hedged in 2014, all with about $90 floors. On the topic of oil movement, I believe it's important to see the value of connecting new wells in a timely manner and keeping our current production online. We've added 34 gross operated wells in the third quarter, bringing the total for the year to 86, well on our way to 112 for the year. At the same time, it's imperative to keep our eye on all of the 200, plus or minus, operated Bakken and Three Forks wells that were on production as of the end of the quarter. LOE ticked up higher in the quarter, as we brought on a number of wells in areas where infrastructure is not fully developed. As we - as buildout advances, we would expect to see LOE cost continue to drop. Stepping back a bit from operational detail, Oasis has grown rapidly these past couple of years and in the midst of that growth, the company is developing a strong foundation for future success. For 2012, this has been defined by 4 major areas where we have made tremendous progress, those being: holding all of our drill blocks by production, making progress on extensional testing in both the Middle Bakken and the Three Forks in associated well density tests, operations optimization and infrastructure development. As we move into next year, we will be focused on transitioning to full development mode, capital and operating efficiencies and increased realization of the benefits of our robust infrastructure buildout. Clearly, Oasis has come a long way since we posted 5,500 BOEs per day in our first full quarter as a public company 2 years ago. We have since grown by 340%, up to 24,257 BOEs per day in the third quarter of 2012 and have raised our volume guidance for the year. I'll turn it over to Taylor now to give you some our operations detail on the great progress that we've made thus far.

As Tommy mentioned, holding our acreage through production has been a big focus for us in 2012. We have been successful on this front and expect to have 260,000 acres held by the end of the year. In addition to acreage retention, our land team has also done a great job picking up additional acreage in and around our core blocks at very competitive prices. They've increased our current net acreage position to approximately 333,000 net acres. About 60% of this acreage has been added on the east side in our Cottonwood area, where we have made significant strides in well performance, cost reduction and importantly, improving out the potential of the Three Forks. We've added over 20 controlled drill blocks for about a 10% increase to our controlled blocks and inventory so far this year. As mentioned above, early results of our extensional Three Forks test in Cottonwood are encouraging. But let's talk a bit about our Three Forks program. We have drilled and completed 3 extensional Three Forks tests so far this year, 2 in Cottonwood and 1 in eastern Red Bank. The 2 Cottonwood tests, the Zdenek [ph] and the Orion [ph] have been producing for about 2 months, and early production from these wells looks very similar to other Bakken producers in the area, with EURs in the 400,000 plus MMBOE range. This is very encouraging because these wells were drilled on the north and south end of our Cottonwood block. And if this performance holds up in the area between the wells, we could end up adding over 230 wells of drillable primary inventory in the Three Forks. In the eastern Red Bank, the Arlos [ph] well came on in September, and early results are again very similar to Bakken producers in that area, indicating that this well should be economic, with an early EUR over 450 MMBOEs. In addition to these producers, we are also currently drilling an extensional test at the Mercedes location in south central Red Bank and have drilled, but not yet completed a Western extensional test at the Justice [ph] well in Hebron. These Three Forks tests are obviously important to understand our inventory, but are also important from an operational standpoint so that we can design our infill patterns to efficiently drain reserves and not over capitalize our program. To advance our infill development understanding and spacing, we drilled a number of pilots in inner well spacing tests in 2012. The results of those tests, combined with micro seismic and other subsurface data and modeling, lead us to believe that we will need at least 4 Bakken wells and 3 Three Forks wells in the Indian Hills and South Cottonwood areas. We are still testing our other areas and think that we will need at least 3 Bakken wells and in the areas where the Three Forks is economic, an equal number of those wells. Further testing in 2012 and 2013 will allow us to confirm the number of wells needed for infill development. Let's switch gears now and talk some about our operational efficiencies. As Tommy mentioned, we're ahead of schedule in reducing our drilling cost from $10.5 million to $8.8 million. We've already reached that mark, thanks to the work of our operations team in Houston and Williston. The big areas of impact have been bigger cost reductions, increased efficiency, improved cycle times and significant cost savings on the material side. Not including in the -- included in the savings are the cost-reductions provided by our frac operations by OWS. On the efficiency side of the business, we continue to drive down drilling days and cycle times on fracs. We now drill wells in 23 days, spud the rig release, and we recently set a new pacesetter mark of 15 days for a 10,000-foot lateral well. We were also frac-ing 36 stage wells in less than 5 days, and we recently frac-ed a 28-stage well in 37 hours with the hybrid sleeve system. One of our big initiatives this year was launching field operations with OWS. Many people have asked us if we would do it again, if given the option, and the answer has always been yes. OWS provides us the opportunity to continually improve our stimulation on both third-party and in-house frac jobs through an increased awareness of stimulation design and execution. We are currently operating on a 24-hour basis and have been frac-ing about 100 stages per month for the last 3 months. We expect this to increase in the coming months to the point where we can handle about 40% to 50% of our frac jobs on a 9-rig program. To-date, we have saved about $30 million of CapEx, which is the high end of what we had forecasted for the full year of 2012. We are still on track to recover the original equipment investment in less than 1 year. To complement our drilling and completion gains, we've also made big strides on infrastructure. Tommy discussed oil infrastructure, so I will cover saltwater and natural gas. As of September 30, we had approximately 35% of our operated water production flowing through our operated SWD pipeline system. We expect to have approximately 50% of our operated water production flowing through the pipeline system by year-end 2012. Additionally, we currently dispose of over approximately 60% of our operated water production at our operated disposal wells and expect this to go to 85% by year-end 2012. This continued expansion of our SWD systems has already reduced costs and is expected to reduce lease operating expenses related to SWD throughout the remainder of 2012 with further reductions expected in 2013. On the gas transportation and processing side of the business, we currently have approximately 85% of our wells connected to sales. When we report our gas production in our financial statements, that number only includes volumes that are sold. The majority of our production goes to Highland on the west and Bear Tracker on the east. The last major area left to be fully connected is the North Cottonwood. Bear Tracker is currently building out a gathering system in this area, with some of the wells currently connected. The balance should be online by the first quarter of 2013. Our efforts to develop infrastructure are allowing us to maximize price realization, decrease production costs and ensure our wells can produce without interruption. I will now turn the call over to Michael to cover more of the financial details.

Thanks, Taylor. We had another great quarter, topping production estimates set for the quarter and driving well costs down faster than anticipated. Based on our full year forecast for CapEx we laid out in August, we have approximately $220 million of capital remaining to be spent in the fourth quarter. With 26 gross operated wells remaining to be completed and an average working interest between 70% to 75%, plus nonoperated capital of $20 million, drilling and completion capital would be about $183 million. When we add 25% of the full-year infrastructure and non-E&P capital budget of $37 million, we appear to be on target with our $1.06 billion budget. We continue to experience significant improvements on the oil differential front. We went from 14.5% in the first quarter to 11.7% in the second quarter to 9.4% in the third quarter. We expect the downward trajectory to continue, given the favorable pricing that we have been experiencing starting in September. We had an average price per BOE of $80.08, excluding hedges and EBITDA per BOE of $62.37. Natural gas production volumes spun down in the third quarter, after a great run starting about a year ago. Like Taylor said, we expect natural gas volumes to continue to grow as we connect more wells to existing infrastructure and as we bring out North Cottonwood in the first quarter of 2013. Pricing has come down off of its peak, largely due to the impact of lower NGL pricing. In the third quarter, adjusted EBITDA was $139 million, a 28% increase over the second quarter. We had $407 million of cash and short-term investments on the balance sheet as of September 30. After quarter end, we increased our borrowing base another $250 million to $750 million, which all remains undrawn. With cash and our borrowing base, we have approximately total liquidity of $1.2 billion to invest in the business. We continue to have a strong balance sheet, which gives us both security and flexibility to grow in a variety of commodity price and operating environments. As we noted in the press release, DD&A increased quarter-over-quarter. As we've been saying, DD&A is a lagging indicator of well cost, and the impact of well cost increases in the first half of 2012 made their way into our DD&A numbers in the third quarter. We should start seeing the impact of our well cost savings hit DD&A sometime in 2013. We remain disciplined with our capital and have been rapidly growing the company, while managing costs. With that, we'll turn the call over to Brandace, to open the lines up for questions. Brandace, you can open up...

[Operator Instructions] Your first question comes from the line of William Butler with Stephens.

Can you all talk a little bit more specifically on the down space testing that you did in Indian Hills? I mean, you all, I think, indicated that at least -- indicates that you can do 4 and 4 Middle Bakken and Three Forks per section, but any more specifics on that?

So in that area, we did 2 full infill pilots. One was actually just 4 Bakken wells without the Three Forks and there was about 4 evenly spaced, and then we did a 3 Bakken and 3 Three Forks test. We also have a micro seismic array across the area where we had the 3 Bakken and 3 Three Forks wells. And then did a number of inner well spacing tests with well pairs across the area. And based on all that information, we think it's -- at least will be 4 Bakken wells and 3 Three Forks wells in that area. And in the area we call Alger [ph], which is the very south end of the -- area on the east side of the basin.

Okay. And so that implies 0 communication between those, I guess?

We see communication in some cases when we stimulate the wells. We don't have enough information, yet to say what the impact ultimately will be on reserve for production. We do know that early results of the wells generally looked pretty similar to other wells in that area for the wells that were spaced closely.

Could some of that communication actually enhance the results?

Yes, it certainly could. When we frac wells in close proximity -- for example, we've got a number of Three Forks, Bakken wells that we frac at close proximity, and they could enhance production.

Okay. And so those EURs, then, would be in line with what you all have already spelled out in sort of terms of single well economics for that area?

Yes. We've maintained the same single well economics at this point that we've talked about in the past for Indian Hills.

Okay. And then, going over to the North Cottonwood area in the Three Forks test that you did there. I believe it was the Zdenek [ph]? How many more wells would you need to drill in that area to add -- I believe it is 230 additional Three Forks -- to add that to the primary inventory? What's it going to take in terms of just feasibility?

Yes. It's very big area between that Zdenek [ph] well and the Orion [ph] well. So there's probably 5 to 10 wells that you're going to need to drill on there, really, to firm all that up. And we'll drill some of those -- quite a few of those wells next year.

Okay. So that could be something -- by midyear, you'd be -- assuming that the results are repeatable by midyear, you might be comfortable with that?

Yes. I'd say to really confirm it in that larger area, it's going to be more like end of next year.

Okay. And then, did you -- I may have missed this, but did you all indicate, in terms of thinking about 2013, about how much of your drilling would be off pads now that you've done a lot of HBP drilling? I apologize if I missed that.

For...

For '13.

For 2013...

We've been [ph] kind of talking about 50% to 70%. We're still going through that budgeting process and figuring out exactly how things are going to be set up next year. But call it around 50% to 70% will be on pads.

And how much -- and that could obviously help that $8.8 million well cost. Can you all help quantify that yet?

And that's why we were talking about, and Tommy mentioned, you're at $8.8 million now that you can reduce -- going into, kind of, that more development-type mode next year, you can reduce about 5% to 10% well cost, hopefully, next year. So we're hoping to get it to $8.5 million or below.

Your next question comes from the line of Brian Lively with Tudor, Pickering, Holt. Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: You guys have done well in terms of providing some color on what your expectations are for taking the well cost down next year. I was hoping if you could provide, maybe, some similar color as you put together the entire sort of LOE picture, and what should we expect in terms of savings going into 2013?

So we did have an uptick as we -- this quarter, and as we've talked about, that was associated with not having fully mature infrastructure in all the areas where we're drilling. So there's some areas, especially, over on the west side of our position where we don't have all of our SWD freshwater supply and importantly, also the electrical grid in place to handle all of our wells, so that's resulted in some increase in cost in those areas. And then so to give you a little more color on electrical grid, where we don't have electricity in place to connect, in a lot of those wells, since it's short term, we're using generators. And that can add a fair amount of cost, and like I said, it is short-term as we get those wells hooked up. So as we go into fourth quarter and for sure into 2013, you're going to see the cost continue to come down and get back more into the $6 range. Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: All right. And then, on the capital side, getting to the $8.5 million and below, what are you guys looking at in terms of the buckets of getting the cost down further than where they are today?

So the big impact items at this point, going forward, one will be pad drilling. We talked about kind of 50% to 70% of our wells will be on pads next year. Continued improvements in efficiency side of the business will be another one. And then, as well, we expect to have some continued savings on the vendor side. Not as big as what you saw this year, but some savings on the vendor side. Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: And then, of the total cost that you guys have brought down from the $10.5 million, how much of that would you frame as being more structural versus cyclical? Meaning, if crude prices really go up again, how much of those savings do you think you would lose?

It's not like pricing, it's really also activity levels in the basin. And even as prices held in for parts of the summer, we're in that $90 range. You continue to see rig count moderate, and it's come down to recently being close to the 200-rig range. I think recently, 205 rigs. At the peak, it was closer to 235 rigs. And so with excess equipment capacity in the basin, we think you're going to continue to see the cost savings that we're realizing. When you have that excess capacity, there's the ability to get the efficiencies out and for vendors to -- those competitive in the basin, to continue to act competitively. Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Will you, in 2013 then, if you're able to realize the higher margins and the lower well costs, would you -- will you accelerate, then, to use up the cash flows? Or how you're thinking about that?

That's one of the scenarios, we're just working on the budget right now. And as you guys have heard us talk about, we kind of target 120 gross operated wells for next year, plus or minus, and kind of -- to stay, kind of, in the same capital range. But one of the scenarios that we'll look at will be to -- if we have the flexibility to ramp-up at the end of the year, but we're still doing all that work now.

Your next question comes from the line of David Snow with Energy Equity, Inc.

What type of drilling mud are you using? Are you using oil-based generally?

We use oil-based invert mud drilling the vertical part of the well, and actually, all the way down through our curve. And then, as we drill the horizontal, we switch to saltwater mud. And almost all the wells we drill are in that -- drilled that way.

Why does it change to saltwater mud as you go horizontal?

With the saltwater mud, we are able to get the wells drilled -- one, it's cheaper. But also, the weight that we need for drilling is easier for us to control.

Is there less...

It's a more cost-effective means, and also for weight of the mud, it helps us.

Is there less well bore damage as you go horizontally too?

With saltwater versus oil muds, I don't really think there's a lot of difference. We don't think that there's a -- we're drilling in the Middle Bakken, which is clastics and dolomites and limestones, things of that nature. And we don't think drilling [ph] clays are a big problem, however, we do use saltwater, so that would help with that.

But going down, would that help you get a better well going down, I guess, in terms of just damage? You don't really care on the damage side?

I don't think it makes a lot of difference. We don't think it makes a big impact because the frac gets past all that.

And then are you still comfortable with 36-stage model? Or do you see some potential to increase or decrease that?

It depends on the area, where some areas where we continue to use 36-stage fracs. We do have some areas where we have pulled back on a number of stages. So an example of that is in northwest Red Bank, and we've gone back to 28 stages in that area. So generally, our wells are somewhere right now between 28 and 36 stages depending on the area, the rock quality, the thickness of the reservoir, water saturations, things of that nature.

And the average length, what are you running?

Average well bore length is around 10,000 feet lateral.

Okay. So the lateral is 10,000 feet, and you're -- there's no thought of going more than 36?

Not at this point. We've done an extensive amount of testing on this. And in fact, that's why in Red Bank, we weren't getting the kind of EUR uplift we needed to justify the incremental cost, so we backed off. So at this point, I would tell you that it's either -- we've got some areas where it's going to be 36s. We've got some areas it's going to be 28s. We've got some areas where we are using 30 to 32, but that's all based off of testing that we've done over the last 18 months.

Your next question comes from the line of Michael Hall with Robert W. Baird. Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division: I guess, first, I'm just coming back on the cost side of things. You mentioned $300,000 of savings per well using OWS. That's versus I think, $600,000 you've talked in the past. Is that just a function of doing the math and saying you're only using it for 50%, roughly, of the wells that you're turning? Am I thinking about that right?

Yes, exactly. What we've said was is $300,000 average over the entire program, and it's about 50%. So you're exactly right. Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division: Got it. And then is there any way to push that 50% higher any -- without any material increases in capital, or how should we think about that?

You mean -- yes, I think at this point, it would be a function of efficiency, not so much a function of us adding a separate spread. Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division: Yes. I guess, I'm just trying to understand what on the efficiency side of things you can do with that spread to further support your program?

Yes. So it's basically cutting down on cycle times. Taylor mentioned that we did -- what was it, 28 stages in 37 hours? So if we can continue to do -- if the recovery results continue to hold and we continue to do more of those kinds of things, then, we can do more work with the same iron.

So one thing that will help us as we go into '13 and '14, for sure, is more pad operations. We're able to frac multiple wells with the crew from the same pad. And so that will help some. We think we're going to be about a 40% to 50% range as we end [ph] out this year and going into next year. Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division: Okay. And what -- I mean, I'm just trying to get a sense of potential magnitude of change. I mean, are we talking about maybe another 10% or -- I mean, any quantification around that?

Yes. I don't know that I would get too wild with it at this point, Michael. Do we go from 50% to 60%? Possibly, but we'll just have to see. Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division: Fair enough. And then, you mentioned you picked up some acreage. I was just curious where that was at or is it just more kind of one-off additional pieces of acreage, or was that any kind of material block? And then, we've seen a lot of deals in the Bakken. You guys haven't won any of them. I'm just kind of curious on your thinking of -- of how you're thinking of these deals as they come through. Are you bidding on them? What is it do you think that's, I guess, keeping you out of the winner's circle, if you will, in terms of winning the deal?

Yes, it's -- just about every deal that comes out, we've taken a look at, and a lot of those processes we've participated in. We just haven't gotten there. If you step back, look at last year, one of the challenges that we had was is look, if you pick up one of these things, you better be able to go out and execute on it. And we weren't comfortable that we could secure the additional services at a reasonable price to able to do that. So that would impact our view of value or what we would be willing to pay for things. But we continue to look. We look for areas where we may have a bit of a differential view, just like when we did the deals over in Montana a year or so ago. Some of the acquisitions that we've done on the acreage front this year have been scattered. I mean, the guys are working it all the time. And we continue to pick up bits of acreage within our blocks, within the drilling program. We did do 1 large deal over on the east side that -- kind of in the middle of Cottonwood that helped us fill in a bit, which is the 20, plus or minus, drill blocks that Taylor mentioned that we add on the operated basis, and it was how many acres?

There was about -- in a single deal, there was about 9,000 acres. And in total across that area, we've probably added around 18,000 acres this year. Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division: Got it. And I guess, as you start to get more into the development kind of mode in '13, and you've brought the cost down to your point, you're not really maybe running against the same held-by production goal that you were in the past. Is it fair to think you might get more aggressive on what you're willing to bid on these deals? Does the Bakken remain your kind of #1 target, if you will? I know you've talked about other kind of new venture activity as well.

Yes. For sure the Bakken/Three Forks is our cornerstone, and it will be. And we'll keep looking at these things and see if we can get a bit more competitive. I mean, with scale, as we've talked about before, you know -- when you look at what guys are doing on the operating front and having the infrastructure in place, some of those kinds of things, maybe, give us enough of an advantage to bolt on a few more things in our core areas. Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division: Okay. That's helpful. And I guess, just on that 10,000 acres you said you added, do you know what exactly did you spend on that, or have you already told us?

Well, for this acreage that we added on the east side, it's been under $1,000 an acre.

Your next question comes from the line of Marshall Carver with Capital One South Company.

On the fourth quarter guidance, what is your forecast of the number of wells -- net wells that would be completed? I saw there was a big uptick from 2Q to 3Q. Where -- what should we expect for 4Q?

Yes. We were at 34 gross operated going to 26 in the fourth quarter. Do you have the net?

And then the net on an operated basis is kind of 19 or so, operated.

Okay, and probably what, 2 or 3 non-op?

Right.

Okay, that's helpful. And then, when do you plan on giving full guidance for 2013?

It will probably be just after the first of the year. Our typical cycle, we work through the budget now and typically get that nailed down in December. But we always hedge a bit because we never know if we may have a few tweaks to make. And so I think last year, it was right after the first of the year when we provided the -- yes, end of January, so probably more in line with that.

Your next question comes from the line of David Tameron with Wells Fargo.

You may have just answered this question, but if we think about '13, just in terms of general framework, should we think about 2/3 Williston, 1/3 East -- everything else as far as the CapEx allocation?

It's early, Dave, to talk about that. But you can look at, kind of, historic spend and call it 60-40 west and east. And it's probably going to be in that neighborhood, but it can be plus or minus 10% on either side.

Okay, that's helpful. And then you may have mentioned this, but drilling days, what are you guys running at right now as far as in the second half of the year?

It's like -- Taylor, it's 23 spud to rig release?

Yes.

23? Okay.

Yes, spud to rig release.

Okay, and then final question. And you talked a little bit about the price outlook, but can you just give us more color on what you think of '13 as far as just general pricing, take away from the basin, et cetera? Kind of just what you guys are modeling, or how you guys are thinking about that?

Yes, I think we'll still, as we look into next year, kind of stick with our what we call the historical norm of 10%, Michael, plus or minus 10%?

Yes, 10%, which is kind of your trucking costs from kind of the lease. And so clearly, with Banner, our oil gathering system going in place, that'll save us on the differential. And we've kind of talked about kind of a 4% or $4 benefit on the differential side with a $2 cost. So the 10% would be on a -- prior to that gathering system. But most of our oil will actually be on that gathering system going forward.

Okay. So outside of -- it might go outside the gathering, outside the impact specific to you guys, just probably speaking, you don't -- you guys, it doesn't sound like you sense or anticipate any big change in to the pricing out there?

It's hard to know. And so we kind of go to the historical norm. And what you're seeing, kind of more recently and why those differentials -- we kind of talk about first, second, third quarter, they've continued to decrease. And we expect fourth quarter to be pretty tight as well from what we've seen so far. And some of that rail versus pipeline dynamic. Historically, we've pointed everybody towards that Guernsey pricing as a proxy for where our differentials are. But that's changed a little bit due to the difference right now in pricing structure pipeline versus rail. The rail is much tighter, pricing-wise, than pipeline is.

Your next question comes from the line of Dave Kistler with Simmons & Company. David W. Kistler - Simmons & Company International, Research Division: Going back to completions for a second. Uptick of 34 in 3Q and guiding to 26 in 4Q. Is there a reason that that's ticking down? Did you have a lot of completions that came in maybe at the tail end of September that reduces October? Is that 26 making it winter weather? Is there propensity for that to move up and take your well number beyond 112 on the year?

Yes. I think at this point, part of it is just the guys -- I mean, we were just able to get more work done. And we had several wells in inventory where we had a little mechanical work to do to be able to bring those on. As we go into the fourth quarter, I think 26 is a good straw man. That being said, it may tick up a little bit depending on weather, because if -- the way we're looking at it now, if we can get more done going into the end of the year and not do it in the first of next year, if we're going to have a tough winter, we'd rather do that. David W. Kistler - Simmons & Company International, Research Division: Okay, that makes sense. And then, going back to well costs for a second. You talked about $8.8 million, currently $8.6 million if you adjust for OWS. If we think about kind of an $8.5 million for next year, yet you're talking kind of 5% to 10% savings, it seems like that actually could be biased downward from there. Was that $8.5 million inclusive of OWS or exclusive?

No, $8.8 million is without OWS. $8.5 million is without OWS. David W. Kistler - Simmons & Company International, Research Division: Okay. So we could be looking, what, $8.3 million, something like that?

Yes, plus or minus. David W. Kistler - Simmons & Company International, Research Division: Okay. And then, if I tie that, then, to moving from 112 wells this year to straw man of 120 next year, you've basically got your well count dropping -- or going up 7%, 8%, yet your well cost, if say, they're $8.3 million versus the season average, maybe $10 million -- maybe I'm a little higher for that for this year -- is a dramatic decrease. It would seem like CapEx would certainly be biased downward. Am I off-base or do I look at it and say, okay, it's going to be flat and activity gets accelerated or capital will used elsewhere? How do I think through that?

What we've talked about, Dave, is kind of that 120 was kind of the first look at it. It's a little bit more activity than this year, which is what you'd expect given efficiencies. And that could get you to a capital number with working interests, non-op piece [ph], infrastructure and kind of all the other non-E&P capital, like you -- exactly like you said. You'd do a little bit more work than you're doing this year, and you'd spend probably, call it, $100 million less and you'd be in more of that 950 range. The flip side is maybe you'd continue to do a little bit more activity than that. And if you were, let's say, 130 or 140 gross wells, then your capital number would be back into that $1.06 billion range that we're at this year, but you'd do significantly more work. And we're just too early to know exactly where we'll shake out on that. David W. Kistler - Simmons & Company International, Research Division: Okay, that's really helpful. And then, just one last one. With respect to the DD&A that ticked up and obviously incorporates historical well costs like $10.5 million at previous reserves, can you give us any sense of magnitude in terms of how you see that coming down in '13? And obviously, I would imagine reserves go up, well costs go down, the math would drive a pretty big drop.

Yes. And that is a backward looking thing, but we're not forecasting at this point what that drop will be. But just given the move down in well cost, like you were saying, that's -- that, in itself, should impact it. We do DD&A rate setting twice a year, so you should start to see that in '13.

Your next question comes from the line of Gail Nicholson with KLR Group.

A couple of quick questions. Regarding that hybrid sleeve that you did, was that in the Red Bank area?

That was in Red Bank, correct.

Do you have any expectations of taking that hybrid sleeve and maybe doing it in a higher-pressure, deeper portion of the basin?

We may. And then first thing we want to do is take a look at the results of the wells. So that's going to take us time. We've got to -- it went on production, but I think it's kind of logged off. We've got to go in and clean the well out and then watch results for at least the end of the year and early next year and then we might get another one if we get into '13.

And then, what's the cost savings versus using that hybrid sleeve versus a normal plug and perf?

I don't have the cost numbers yet.

Your next question comes from the line of Ron Mills with Johnson Rice. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: The question on the hybrid sleeve was just answered. But Taylor, I'm hearing some people are using more -- or starting to use more slick water in some completions out there. Are you still using crosslinked gel? Are you starting to evaluate different delivery systems, or -- just curious as to what's changing now as you continue to optimize the completions.

Yes. There is -- in our frac designs, we've always had a component of slick water. So at the front end at each stage, we've always had slick water. We have been looking, especially at some parts of the basin, using quite a bit more slick water, and so we're testing that -- actually a well we're frac-ing right now in Red Bank that's largely a slick water frac. We still are testing the concentration of slick water versus crosslinked gels, and obviously always look at other people's wells in the basin as well. So always trying to optimize and improve the frac jobs and looking at all of the options. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: Okay. And when you -- and this may be a Michael question. When you look at your program here in the fourth quarter and just from an expectation level next year, how should we think about your net working interest in your operated well program? I know it's been moving up over the course of 2012. Where does it stand now, and do you think you can go up further from the current level?

Yes. So at the beginning of the year, we came in budgeting around just under 70% average working interest. And our wells this year certainly have moved up more in that kind of mid- to high-70s range. As we go into next year, we're still looking at where those working interests will shake out for that program next year. And it's -- but call it somewhere in that, probably, low-70 to mid-70 percentage range will be a good place to look at. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: Okay, good. And I think, to follow up on one of Dave's questions earlier, just about direction with the CapEx. You talked about -- could be lower, could be similar. To the extent that you continue to get more efficient on both the drilling and completions, is the expectation -- would you potentially stay at 9 rigs throughout next year, or would the rig count really be driven by what your targeted well activity is?

Yes, we'll probably have a well count that will go towards -- and kind of like this year, we initially said that we're going to count -- go to 12 rigs, and we've brought in 3 new build rigs that helps our development program. But we also dropped rigs as we got more efficient to manage within a budget level. So we'll continue to do the same thing next year. We'll probably gear around a number of wells, and the rig count will just be what will help us get there. If we get way more efficient, perhaps you drop rigs, and you can make a decision at that time. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: Okay, great. And then lastly, if you look at your drilling next year, the pad drilling versus continued lease conversion, is pad drilling going to be more focused on -- in the West Williston area? And -- or is that -- I'm just trying to get a sense of which areas will be more focused on pad drilling versus converting to held-by production.

A little more pad drilling in West Williston, just more mature. As you know, we've been doing more drilling in that area, so more development pad operations. We're still drilling a lot of first wells on the east side of the basin, especially in Cottonwood.

Your next question comes from the line of Ryan Oatman with SunTrust.

Most of my questions have been answered, but I was just trying to reconcile the $872 million in accrued CapEx with the $777 million in cash capital spending. Does that roughly $100 million delta -- do I see that hit the cash flow statement in 4Q? Does that delta just kind of stay steady or grow over time? Can you kind of walk me through the accounting aspects?

Yes. So Ryan, it's Richard. The way to think about it, it's just the way typical accruals work, and so -- and typically the way that working capital works. So you make an accrual for what you think you're really spending in that quarter, and then you end up paying for a little bit later. And so just it's just kind of always a little bit behind your total spend, especially as you're accelerating. And so if you ended up being flat, you would -- flat CapEx, even every quarter, even every year, you'd see your cash flow statement begin to look much more like your actual accrual number.

Your next question comes from the line of [indiscernible] Mahanti with Bank of America.

[indiscernible] in the next several [ph] quarter are holding up very well despite a not-so-good day. Most of my questions are answered, but just a quick one on the type [ph] curve. How do you see that sort of panning out in 2013? Does the Middle Bakken curve still hold good going forward?

I don't think that we have any reason to expect -- to think that is going to be any different than what we've already included in our corporate presentation. I think that still holds pretty well.

How do you see that changing, if any, for the Three Forks wells that you plan to drill or you're drilling right now?

I don't think we do. I think what Taylor said earlier is in a lot the more recent tests, we've seen wells, especially over on the Cottonwood side, that are pretty similar to the Middle Bakken wells.

Just a quick follow up on the differentials. Do you see these excellent differentials sort of holding up in 2013, improving, actually, going forward?

Yes, what we talked about on differentials is that when we look at kind of longer-term out, it -- we still go back to the historical 10% differentials in the basin where they've been. For us, as we have a gathering system, it's improving from there. But that 10% kind of lease differential is probably a good number to go with. Certainly, here recently, we've seen some benefit from all of the rails -- rail systems that have come in. And they've bid the crude and the differentials up or tighter for us here in the near term, and we'll see that benefit in the fourth quarter, maybe earlier part of next year. But certainly don't necessarily expect that going forward. We'll see how that continues to play out.

Your next question comes from the line of Peter Mahon with Douglas (sic) [Dougherty]. Peter Mahon - Dougherty & Company LLC, Research Division: I just had a couple follow-up questions. A few of your peers have talked about there being multiple benches in the Three Forks formation. I just wanted to get your thoughts on whether or not any of your testing has given you a sense whether that's viable in any of your acreage or not?

The short answer is, is that we're not there yet. Although, as time goes on, you get more data, it looks more and more intriguing. We cored a well down in Indian Hills, but haven't gotten all that core work back yet. So we hedge a bit until we have some real in-house data on that. But certainly, so far, it looks increasingly intriguing to us. Peter Mahon - Dougherty & Company LLC, Research Division: Okay. Great. And you mentioned, you do have some testing that's being either conducted right now or planned this year to determine that?

Core work. Now as we go through the budget process here, we'll figure out, based on all that, whether we try to drill a well in one of those benches next year. Peter Mahon - Dougherty & Company LLC, Research Division: Sure, okay. My second question has to do with the water disposal system. I mean, you -- it's -- from the numbers that you gave us in Q2, it sounds like there hasn't been a ton of progress made, so -- since then. What are the hurdles that you guys are running into to really build that out, and what gives you confidence that you can kind of reach your goals by the end of the year?

Yes. So we've continued to, from Q2, the biggest progress was probably been getting the pipe in the ground. The number of disposal wells hasn't changed a lot at this point. So it's getting the connections from the producing wells to those disposal wells. And a lot of that is going to come together in 4Q and in 1Q next year. It'll just take time to get all that pipe in the ground.

You also hear [ph] your well [ph] count by 20% over the quarter. So just keeping up with the growth that we have on new wells coming on is also why it's kind of staying in that flat range.

There are no further questions. I would like to turn the call back over to Oasis Petroleum for closing remarks.

Thank you. This has been a year where Oasis has differentiated itself from its peers, and we're proud of what the team has done across all fronts. This year, we're putting in a strong foundation with more efficient operations, lower well cost, improved uptime and optimized price realizations. We also continue to rapidly grow the company, while maintaining a strong conservative balance sheet. We believe we're focused on the right things and have the right people in place to execute on our plan. Thanks again, for everybody's participation on our call today.

Ladies and gentlemen, thank you for your participation. This does conclude today's conference. You may now disconnect.