Chord Energy Corp (CHRD) 2012 Q3 法說會逐字稿

Good morning. My name is Brandice 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 of Oasis Petroleum.

(Operator Instructions)

After the speakers' remarks there will be a question-and-answer session.

(Operator Instructions)

I would now like to turn the call over to Michael Lou, Oasis Petroleum CFO to begin the conference. Thank you, you may begin your conference.

Thank you. Good morning everyone.

This is Michael Lou. We are reporting our third quarter 2012 results, and we are delighted to have you on our call. I'm joined 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 states that we believe to be forward-looking statements within the meaning of the Private Litigation and 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 and Exchange commission, including our annual report on form 10K and quarterly reports on form 10Q. We disclaim any obligation to update these forward-looking statements.

Please note that we expect to file our third quarter 10Q today. During this conference call we will also make reference 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 our website.

I will now turn the call over to Tommy?

Good morning. We'll follow a similar format to the past where I will cover introductory comments, Taylor follows with more operational color, and Michael will finish with a few financial highlights.

We have 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 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 these topics with a focus on safety, and continue to emphasize this with our employees, contractors and partners to maintain safe work sites across the Basin.

First, drilling and completion costs 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 costs continued to increase largely due to continued service cost creep, and in part due to some proactive regulatory changes enacted by NDIC. Average well costs plateaued in the first half of the year at approximately $10.5 million per well, which is approaching critical threshold you have heard us talk about at about $11 million per well.

With the additional 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 costs down to $8.8 million by the end of the year, but 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 operated program by about $300,000 per well, driving 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 continues 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 costs to $8.5 million or less.

Great job by our entire team coming up with such an impactful plan and then executing on it, save $2 million per well from $10.5 million down to $8.5 million is massively accretive to NAV and our cash flows. In addition, with OWS, we have executed on our plan that we laid out two years ago with results exceeding our original expectations supplementing our cost control efforts.

Second, the team 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 operated 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. 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 marketing and transportation costs of $1.23 for BOE toward differentials.

We continue to have about 60% of our oil on the in field 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 flexibility on even more of our volumes with multiple outlets including six rail loading facilities and four pipeline connections.

In conjunction with physically moving our barrels, we have an aggressive hedge program to protect us financially as we out spend 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 $90.00 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 have 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 build-out advances, we would spent to see LOE costs 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 four 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 Three Forks and 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 build-out. Clearly, Oasis has come a long way since we posted 5,500 BOEs per day in our first full quarter as a public company two 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 will turn it over to Taylor now to give you more operations detail on the great progress that we've made thus far.

As Tommy mentioned, holding our acreage through production as 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 done a great job picking up additional acreage in and around our core blocks at very competitive prices. They have 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 the potential of the Three Forks. We have added over 20 control drill blocks for about a 10% increase to our control blocks in inventory so far this year.

As mentioned above, early results on our extensional Three Forks test in Cottonwood are encouraging. So let's talk a bit about our Three Forks program.

We have drilled and completed three extensional Three Forks tests so far this year, two in Cottonwood and one in eastern Red Bank. The two Cottonwood tests, the [Zedina] and Orion have been producing for about two months. Earlier production from these wells looks very similar to other Bakken producers in the area, with EORs the in the 400,000 plus NBOU 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 eastern Red Bank, the Arlyss 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 the early EOR over 450 in BOEs. 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 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 infield patterns to efficiently drain reserves and not over-capitalize our program.

To advance our infield development understanding in 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 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 infield development.

Let's switch gears now, and talk some about our operational efficiencies. As Tommy mentioned, we are ahead of schedule in reducing drilling costs from $10.5 million to $8.8 million. We have already reached that mark thanks to the work of our operations team in Houston and Williston. The big areas of impact have been vendor cost reductions, increased efficiency, and improved cycle times and significant cost savings on the materials side. Not included in the savings are cost reductions provided by our frac operations by OWS.

On the efficiency side, we continue to drive down drilling days and cycle times on fracs. We now drill wells in 23 days, plug rig release, and recently set our new pace setter mark of 15 days for a 10,000-foot lateral well. We are also fracking 36 stage wells in less than five days and recently fracked a 28-stage well in 37 hours with a hybrid sleep 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 due to an increased awareness of stimulation design and execution. We are currently operating on a 24-hour basis and have been fracking about 100 stages per month for the last three 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 our 9-rig program.

To-date we have saved about $13 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 original equipment investment in less than one year.

To compliment our drilling and completion games, we have also made big strides on infrastructure. Tommy discussed oil infrastructure, so I will cover salt water and natural gas.

As of September 30th, 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 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 of our financial statements, that number only includes volumes that are sold. The majority of our production goes through Highland on the west and Bear Tracker on the east.

The last major area left to be fully connected is in 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.

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 at an average working interest between 70% to 75% plus non-operated capital of $20 million. Drilling and completion capital would be about $183 million.

When we add 25% of the full year infrastructure and non-EMP capital budget of $37 million, we appear to be on target with our $1.06 billion budget. We continued 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 flattened out 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 up north Cottonwood in the first quarter 2013. Pricing has come down off of its peak largely due to the impact of lower NGO 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 surety 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 have been saying DD&A is a lagging indicator of well cost, and 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 Brandice open the lines up for questions.

(Operator Instructions)

Your first question comes from the line of William Butler with Stephens.

Can you all talk a little bit more specifically on down space testing that you did in Indiana Hills? You all I think indicated that at least indicates you can do four, and four middle Bakken and Three Forks per section, but anymore specifics on that?

So in that area, we did two full infield pilots. One was actually just four Bakken wells without the Three Forks and there was four evenly spaced. And then we did a three Bakken and Three Forks test.

We also have a micro seismic array across the area where we had the three Bakken and 3-Three Forks wells. Then we did a number of inner well spacing tests with well pairs across the area. Based on all that information, we think it's at least will be four Bakken wells and three-Three Forks wells in that area. And in the area we call Alger which is the very south end of the area on the east side of the Basin.

Okay. And so that implies zero 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 or production. We do know that early results of the wells generally look 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 fracked in close proximity. And they could enhance production.

Okay. So those would EORs be in line with what you all have spelled out in terms of single well economics for that area?

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

Okay. Thank you.

Going over to the north Cottonwood area and Three Forks test that you did there, I believe the Zed Neck, how many more wells would you need to drill in that area to add 230 Three Forks, to add that to the primary inventory? What's it going to take in terms of just repeatability?

It's a very big area between the Zed Neck well and the Ryan well. So there is probably five to ten wells that you are going to need to drill in 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 mid-year you would be assuming that the results are repeatable by mid-year? You might be comfortable with that?

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

Okay. And then 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 have done a lot of HPB drilling? I apologize if I missed that. For 2013.

For 2013.

Been kind of talking about 50% to 70%. We are still going through that budgeting process and figuring out how exactly things are going to be set up next year. Call it about 50% to 70% will be on pads.

That could probably help that $8.8 million well cost. Can you help quantify that yet?

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

Got you. Sorry if I missed that. Thank you. That's all I got.

Thanks William.

Operator. Your next question comes from the line of Ryan Lively with Tudor Bickering Holt.

You guys have done well in terms of providing color on your expectations for taking the well cost down next year. I was hoping if maybe you could provide 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 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 are some areas especially over on the westside 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.

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 the wells since it is short term, we are using generators. And that can add a fair amount of cost. Like I said it is short term as we get those wells hooked up. As we go into fourth quarter and for sure into 2013, you are going to see the costs continue to come down and get back more into the $6.00 range.

All right. 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 costs down further than where they are today?

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 the efficiency side of the business will be another one.

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.

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 verses cyclical? Meaning if prices go up again, how much of the savings would you think you would lose?

You know, it's not only pricing. It's really also activity levels on the basin. Even as price is held in for parts of the summer, we are in the $90.00 range, you continue to see rig count moderate and it's come down to recently being closer to the 200 rig range. I think recently 205 rigs.

At the peak it was closer to 235 rigs. So with excess equipment capacity in the Basin, we think you are going to continue to see the cost savings that we're realizing. When you have that excess capacity, there is the ability to get the efficiencies out and for vendors as competitive in the Basin to continue to act competitively.

Will you in 2013 then if you are able to realize higher margins and lower oil costs, will you accelerate then to use cash flows? How are you thinking about that?

That's one of the scenarios. We are just working on the budget right now. As you guys have heard us talk about, we kind of target 120 gross operated wells for next year, plus or minus, and stay kind of in the same capital range.

But, you know, one of the scenarios that we'll look at will be if we have the flexibility to ramp up at the end of the year. But we're still doing all that work now.

Appreciate it, guys.

You bet.

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

Good morning. What type of drilling mudding are you using, are you using oil-based mainly?

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

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

With the saltwater mud, we're able to get the wells drilled. One it's cheaper, but also the weight that we need for drilling is easier of course to control. It's a more cost effective means and also for weight of the mud, it helps us.

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

With saltwater verses oil muds, I don't really think there is a lot of difference. We don't think that there -- we are drilling in the metal Bakken which is plastics and limestones, things of that nature. We don't think soil and clays are a big problem here but we do use saltwater, so that would help with that.

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

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

Are you still comfortable with 36 stage model, or do you see some potential to increase or decrease that?

It depends on the area. Some areas where we continue to use 36 stage fracs, we do have some areas where we have pulled back on the number of stages.

So an example of that is in northwest Red Bank. We have gone back to 28 stages in that area. Generally all our wells are right now between 28 and 36 stages depending on the area of the rock quality, thickness of the reservoir, water saturations, things of that nature.

The average length, what are you running?

Average well board length is around 10,000 feet.

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

Not at this point. You know, 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. 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 where it's going to be 28s. We've got some areas where we're using 30 to 32 but that's all based off testing we've done over the last 18 months.

Great of the thank you very much.

You bet.

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

Congrats on the solid quarter. I guess first on my end just coming back on the cost side of things. You mentioned $300,000 of savings per well using OWS. That's verses I think $600,000 you talked about in the past.

Is that just a function of you doing the math and saying you are only using it for 50% roughly of the wells that you are turning? Am I thinking about that right?

Yes, exactly. What we said was $300,000 average over the entire program. It's about 50%. So you're exactly right.

Got it. Then is there any way to push that 50% higher 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 in a separate spread.

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 28 stages in 37 hours. We can continue to do more of those kinds of things, than we can do more work with the same hire.

One thing that will help us as we go into 2013 and 2014 for sure is more pad operations. We're able to frac multiple wells with the crew from the same pad. So that will help some. We think we're going to be in a 40% to 50% range though as we end out this year and go into next year.

Okay. I am just trying to get a sense of potential magnitude of change. Are we talking about maybe another 10%? Or any quantification around that?

Yes, I don't know that I would get too wild with it at this point, Michael.

Okay.

Do we go from 50 to 60%? Possibly. But we'll just have to see.

Fair enough. 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?

Then we have seen a lot of deals in the Bakken. You guys haven't won any of them.

I am just kind of curious on your thinking 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 circle if you will in terms of winning the deals?

Yes, you know, just about every deal that comes out we have taken a look at and a lot of those processes we have participated in, we just haven't gotten there. If you step back, you know, and look at next year one of the challenges that we had was if you pick up one of these things you better go out and be able to execute on it. We weren't comfortable we could secure the additional services at a reasonable price 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 we have done on the acreage front this year have been scattered. The guys were working it all the time. We continue to pick up bits of acreage within our blocks within the drilling program.

We did do one large deal over on the east side 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. How many acres?

In a single deal there is about 9,000 acres and in total across that area we probably added around 18,000 acres this year.

Got it. I guess as you start to get more into the development mode in 2013 and you have brought the cost down to your point, you are 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 number one target if you will? I know you have talked about other kind of new venture activities well.

For sure, the Bakken Three Forks is our cornerstone and it will be. We'll keep looking at the these things and see if we can get a bit more competitive. With scale as we have talked about before, when you look at what the guys are doing on the operating front and having 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.

Okay. That's helpful. I guess just on the 10,000 acres you said you added, do you know what exactly did you spend on that? Have you already told us?

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

Okay. Very good. Thanks, guys.

Thanks Michael.

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

Yes, thank you. 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 uptake from 2Q to 3Q. What can we expect for 4Q?

We were at 34 gross operated, going to 26 in the 4th quarter. Do you have the net?

We counted 19 or so, operated.

Including 2 or 3 non-op.

That's helpful. When do you plan on giving full guidance for 2013?

Probably be just after the first of the year. You know, 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. You may have a few weeks to make.

So I think last year, it was right after the first of the year when we provided -- end of January. So probably more in line with that.

Thank you and congratulations on the progress.

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

Hi. Good morning.

Good morning David.

You may have just answered this question. If we think about 2013 just in terms of general framework, should we think about 2/3 Welliston, 1/3 everything else as far as the CapEx allocation?

It's early, Dave, to talk about that. But you can look at kind of historic spin 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, okay. That's helpful. Thanks.

You may have mentioned this. But drilling days, what are you guys running at now as far as in the second half of the year?

Taylor's 23 spud to rig release.

23, okay.

Spud to rig release.

Okay. Then final question. You talked a little bit about the price at liquid, can you just give us more color on what you think in 2013 as far as just general pricing take away from the Basin, kind of what you guys are modeling and how you guys are thinking about that?

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 cost from kind of the lease. So clearly with banner our oil gathering system going in place, that will save us on the differential. We kind of talked about a 4% or $4.00 benefit on the differential side with a $2.00 cost.

So the 10% would be prior to that gathering system. But most of our oil will actually be on that gathering system going forward.

Okay. So might go outside of the gathering, outside of the impact with you guys broadly speaking it, doesn't sound like you sense or anticipate any big change in the pricing up there.

It's hard to know. So we kind of go to the historical norm. What you are seeing kind of more recently and why those differentials. We kind of talked about first, second, third quarter they've continued decrease and we expect 4th quarter to be pretty tight as well from what we have seen so far. Some of that's that rail verses 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 verses rail. The rail is much tighter pricing wise than pipeline is.

All right. That's all helpful. Thanks for the color.

Thanks, David.

Your next question comes from the line of David with Simmons & Company.

Going back to completions for a second, you know, uptick of 34 in 3Q and guiding to 26 in 4Q, is there a reason 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 thinking in winter weather, and is there propensity for that to move up and take your well number beyond 112 on the year?

I think at this point part of it is just the guys, I mean we were just able to get more work done. We had several wells in inventory where we had a little bit of mechanical work do to be able to bring those on. As we go into the 4th quarter, I think 26 is a good straw man.

That being said, you know, it may tick up a little bit depending on weather. 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 the first of next year, if we're going to have a tough winter, we'd rather do that.

Okay. That makes sense. Then going back to well cost 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 are 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.

Okay. So we could be looking at $8.3 million or something like that?

Yes, plus or minus.

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 costs, say they're $8.3 million versus using an average, maybe $10 million, may be high 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 be used elsewhere? How do I think through that?

What we have talked about, Dave, is kind of the 120 was kind of the first look at it. It's a little bit more activity than this year which is what you would expect given efficiencies and that could get you to a capital number with working interest, nonOP piece, infrastructure and all the other non E&P capital. Exactly like you said you would do a little bit more work than you are doing this year, and you would spend probably $100 million less and be more in the $950 million range.

The flip side is maybe you continue 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 would do significantly more work. We're just too early to know exactly where we will shake out on that.

Okay. That's really helpful. One last one.

With respect to the DD&A that ticked up and obviously incorporates historic 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 2013? Obviously I would imagine reserves go up, well costs go down. The math would drive a pretty big drop.

Yes, that is a backward looking thing. But year not forecasting at this point what that drop would be.

Just given the move down in well cost like you're saying that should in itself impact it. We do DD&A rate setting twice a year. So you should start to see that in 2013.

Okay. Well fantastic progress guys, thanks so much.

You next question comes from the line of Gail Nicholson with KLR group.

Good morning gentlemen. A couple quick questions. Regarding the 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 at a higher pressure deep proportion basin?

We may. The first thing we want to do is take a look at the results of well. So that's going to take us some time.

Well production, I think it logged off. We have to clean the well out and watch results for at least the end of the year and early next year and then we might do another one if we get into 2013.

What's the cost savings verses using the hybrid sleeve verses a normal plug and [parf]?

I don't have the cost numbers yet.

Okay. Great. Thank you.

Your next question comes from the line of Ron Mills with Johnson Rice.

Good morning.

Hey Ron.

Question on the hybrid sleeve was just answered. But Taylor, I am hearing some people are starting to use more slick water in some completions out there. Are you still using cross link jell or are you starting to evaluate different delivery systems? Just curious as to what's changing now as you continue to optimize the completions?

There is, in your frac designs, we've always had a component of slick water. So the front end of each stage, we have always had slick water. We have been looking, especially at some parts of the Basin, at using quite a bit more slick water. So we're testing that.

It's actually a well we're fracking right now in Red Bank that's largely a slick water frac. We still are testing the concentration of slick water verses cross link gels and I'll just 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 the options.

Okay. And this may be a Michael question. When you look at your program here in the 4th quarter and just from an expectation level next year, how should we think about your networking 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-70's range.

As we go into next year, we're still looking at where those working interests will shake out for that program next year. But call it somewhere in that probably low-70 to mid-70 percentage range will be a good place to look at.

Okay. Good. And then I think to follow up on one of Dave's questions earlier just about directional of the CapEx.

You talked about could be lower or 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 you're targeted well activity is?

We'll probably have a well count that we'll go towards. Kind of like this year, we initially said we're going go to 12 rigs and we 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 number of wells. The rig count will just be what will help usage there. If we get way more efficient, perhaps you drop rigs and you can make that decision at that time.

Okay. Great. Then lastly if you look at your drilling next year, the pad drilling verses continued lease conversion.

Is pad drilling going to be more focused in west Williston area or is that incorrect? Just trying to get a sense as to which areas will be on pad drilling verses converting to held by production.

A little more pad drilling in west Williston. We have been doing more drilling in that area. So more development in pad operations. We are still drilling a lot of first wells on the east side of the Basin, especially in Cottonwood.

Perfect. Everything else has been asked. Thank you.

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 is the way typical accruals work and typically the way working capital works. So you make an accrual for what you think you are really spending in that quarter. Then you end up paying for it a little bit later.

So it's just kind of always a little bit behind your total spend, especially as you are accelerating. So if you ended up being flat, flat CapEx even every quarter or even every year, you would see your cash flow statement begin to look much more like your actual accrual number.

Okay, okay. That's helpful. Thank you.

You bet.

Your next question comes from the line Ipsit Mohanty of with Bank of America.

Congratulations on an excellent quarter holding up very well despite a not so good day. Most of my questions are answered, but just a quick one on the type curve. How do you see that sort of panning out in 2013? Does the middle Bakken curve still hold good going forward?

Yes, I don't think that we have any reason to think that it's going to be any different than what we have already included in our 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 are drilling right now?

I don't think we do. I think what Taylor said earlier is in a lot of the more recent tests we have seen wells that are 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 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, 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 have seen some benefit from all of the rail systems that have come in. And they've bid the crude and differentials up are tighter for us here in the mid-term and we'll see that benefit in the fourth quarter and maybe early part of next year, but certainly don't necessarily expect that going forward. We'll see how that continues to play out.

Okay. Thank you guys.

Your next question comes from the line of Peter Mayhon with Douglas.

Good morning guys. I just had a couple follow up questions.

You know, 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 is viable in any of your acreage or not?

Short answer is we're not there yet, although as time goes on and you get more data it looks more and more intriguing. We poured 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.

Okay. Great. You mentioned you do have some testing that's being either conducted now or planned this year to determine that?

Core work. Now you know as we go through the budget process here we'll figure out based on all that, whether we try to drill well in one of those benches next year.

Sure. Okay.

My second question has to do with the water disposal system. I mean, it's from the numbers that you gave us in Q2 is sounds like there hasn't been a ton of progress made since then. What are the hurdles you guys are running into to build that out and what is your confidence you can reach your goals by the end of the year?

We've continued to -- from Q2 biggest process has probably been on 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 just takes time to get all that pipe in the ground.

You also your count by 20% over the quarter. Just keeping up with the growth we have on new wells coming on also is why it is staying in that flat range.

Okay. Perfect. Thank you very much, guys.

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 are 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 costs, improved up time, and optimized press realizations.

We also continued 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 everyone's participation on our call today.

Operator. Ladies and gentlemen, thank you for your participation. That will conclude today's conference. You may disconnect.