Chord Energy Corp (CHRD) 2014 Q3 法說會逐字稿

Good morning. My name is Kate, and I will be your conference operator today. At this time. I would like to welcome everyone to the third-quarter 2014 earnings release and operations update for Oasis petroleum. Please note, this call is been recorded.

(Operator Instructions)

I would now turn the call over to Michael Lou, Oasis Petroleum's CFO. Mr. Lou, please go ahead.

Thank you Kate. Good morning everyone. This is Michael Lou. Today we're reporting our third-quarter 2014 results. 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 and Exchange Commission, including our annual report on form 10-K and our quarterly reports on form 10-Q. We disclaim any obligation to update these forward-looking statements.

During this conference call, we will also make references to adjusted EBITDA, which is a non-GAAP financial measure. Reconciliations to adjusted EBITDA to the applicable GAAP measures can be found in our earnings release and on our website. We will also reference our November investor presentation, which you can find on our website. I will now turn the call over to Tommy.

Good morning, and think you for joining today's earnings call. Oasis has been and continues to be a growth E&P company. After doubling year-over-year production in 2011 and 2012, and growing by over 50% in 2013, we expect to deliver growth of approximately 35% in 2014. While we have grown rapidly through the (technical difficulties) we have also established ourselves as a low-cost efficient operator in the Williston Basin. Combining operational excellence with a premier position in the core of the Bakken play, I remain bullish about our ability to continue to grow this asset over the long term.

At a high level we continue to focus on growth while being mindful of managing our financial position and optimizing returns. In the midst of this growth, there will be periods of transition, and this year marks one of those times as we began laying the foundation for full-field development. Specifically this year we've been focused on four key object: building out capacity on the in-basin oil, gas, and saltwater disposal infrastructure, enhanced completion technology, optimizing operations around the complexity of full DSU development, and lower bench Three Forks delineation work. Taylor will provide more color on each objective in a moment, but the quick answer is that we continue to make strides on each of these, and we will be in a great position going forward.

Additionally, you have heard us talk about our desire to control certain elements of our business since 2011 when we announced that we were building our first internal frac spread. Now that we have two frac spreads running and we delivered $400,000 of savings per net well again this quarter, we continue to see this component of our business as a key differentiating item, giving us improved quality, dependability and cost of service. We will continue to look for ways to manage our risk across our entire business.

We also manage our outside services to give us flexibility. As we've talked about before, of the 16 rigs we're currently running, 10 of them have contracts that have less than five months remaining. As we head into 2015 this gives us the ability to actively manage our capital program, depending on the operating environment. As always, the oil price environment, service cost environment and our financial position are extremely important in our planning process.

But infrastructure is just as important as we determine both where we drill and how fast we drill. Given the uncertainty on oil prices, it is a bit too early to discuss specific plans for 2015. However, protecting our balance sheet while executing on our plan is very important to us. And we can manage that to our capital plan on our hedged profile, which Michael will discuss in a few minutes. With that, I'll turn the call over to Taylor to discuss our operations in more detail.

Thanks, Tommy. As you saw, we reported another record quarter of production with the volume of 45,900 barrels equivalent per day, represent a quarter-over-quarter growth of 5%. Clearly, it was below our range of 47,000 to 49,000, so I want to make sure you understand what happened and how to think about production growth next quarter. A point I want to emphasize upfront is that the production miss, with the exception of the lower Three Forks under-performance in North Cottonwood, is due to operations and infrastructure and is not a reflection of rock quality. In fact, we are seeing improved performance through higher intensity stimulation that we will cover in more detail shortly.

As Tommy mentioned, there were three primary drivers to the under-performance. First, the combined impact of weather and infrastructure. Second, the impact of high-density spacing units when operations did not go as planned. And third, the delineation of the lower Three Forks benches. All three of these are important now, but will be equally important as we plan for Q4 and for 2015.

The first bucket was related to infrastructure. During times of wet weather, the counties in North Dakota restricted the passage of heavy trucks, which transport both oil and produce water on roads. Because of the road closures coupled with the lack of infrastructure in certain areas of our asset, significant volumes were shut in, which represented about 700 barrels of oil equivalent per day of loss production. In addition, even though we have over 90% of our wells connected to gas infrastructure in certain large DSUs, like the Hagen Banks unit in Indian Hills, the third-party infrastructure was either not able to take all of the produced gas, or infrastructure was not in place when the wells came online.

We ended up clearing about 400 barrels equivalent per day more gas than we expected. While we have found some short-term solutions to reduce gas flaring, the medium- to long-term solution is to get the appropriate gas infrastructure in place ahead of our drilling program. This will be a significant focus for us in 2015.

Second, issues associated with full DSU drill-outs represented about 800 barrels equivalent production per day of our production variance. As we drill spacing units with higher density -- with higher well density, operational issues on a single well can be magnified due to the impact to production on other wells in the spacing unit. On one particular unit, the Mallard, the 13 well DSU, problem well significantly delayed initial production and then forced multiple shut-ins of producing wells for frac protect.

We now believe the challenges in the Mallard unit are behind us, but even more importantly we have taken that experience and used it to improve planning and execution on our development going forward. We have plenty of examples where the surface operations and timing have gone smoothly.

The last bucket of production variance was related to our lower bench Three Forks delineation program in North Cottonwood. We tested the lower benches based on encouraging information from our [cors] last year. Reduction from this program came in light versus our projections, causing a variance of about 600 barrels of equivalent production per day versus our forecast.

Given the results, we have revised our economic boundary for the lower benches of the Three Forks and East Nesson in current investor presentation. This adjustment has minimal impact to inventory, as we have very few wells in the lower bench inventory in this area. Additionally, we have lower production estimates for these wells in our current forecast.

All the variances combined add to 2,500 barrels of oil equivalent per day, and when added to our actual production for the quarter places you at 48.4 thousand oil equivalent per day, or above the midpoint of our range. The point is that the variances are mostly operational or infrastructure, and are things that we will address going forward.

Let's shift for a moment and talk about completion activity. The team did a great job setting a record for the most wells completed by Oasis in a single quarter, hitting 66 gross operated completions. On a net basis, we completed 52.4 wells, but with many of the completions being pushed to the last half of the quarter. Also, while we got eight high intensity completions done in the third quarter, most of that activity will be accomplished in Q4.

In our updated plans, we have pushed out the completion of approximately 15 gross operated wells into 2015 to better account for cycle times associated with full spacing unit development and toi account for potential weather-related delays. This translate into approximately 190 completions in the year compared to our original plan of 205, but most of the capital associated with these wells will hit in 2014. We had 61 gross operated wells waiting on completion at the end of the third quarter, and we expect to have 79 wells waiting on completion at the end of the year. At the beginning of the fourth quarter we again experienced weather-related road closures, and we are forecasting a more conservative approach to downtime, including frac protect.

Due to the increased impact of weather as we continue to get our infrastructure in place, and due to a larger percentage of frac protect associated with higher density DSUs, we have moved fourth-quarter downtime from 5% to 6% to 8% to 10% on a volumetric basis. With all of this in mind, we are expecting to produce between 47,000 and 49,000 barrels of oil equivalent per day in the fourth quarter.

Outside of North Cottonwood, you can also see in our presentation that in areas where the lower benches work, the wells performed very well in relation to our Three Forks tight curve and have generally trended above the midpoint. In the White unit in Indian Hills, we did an infill pilot, testing wells into the third bench of the Three Forks using slickwater. We completed 70 wells in the unit in early October. While the unit has less than 30 days of data, it has performed extremely well in early-time results.

Through just 25 days, the Balkan well has cumulative production of over 36,000 barrels of oil equivalent, which results in a 25-day IP of 1,472 barrels of oil equivalent per day on average, which is about 51% above our 750 MBOE type curve for Indian Hills. The Three Forks wells, which include two wells per formation through the third bench, have averaged 41% better than the top end of our 600 MBOE type curve for the Three Forks for Indian Hills.

On another DSU, the Briar unit in Indian Hills was drilled on five well equivalent spacing per formation through the second bench of the Three Forks. We put one slickwater well in the unit in, and through 110 days it has produced nearly 148,000 barrels of oil equivalent, which is over 100% above the 750 MBOE tight curve. This unit has some of the best wells in the Company in the respective formations, giving us increased confidence the development in the area through the lower benches.

Given the strong results on these units, as well as continued successes we have seen on other slickwater wells, we are allocating additional capital to enhance fracture stimulation in the fourth quarter. We will complete 70% of our wells with either slickwater or high-volume sand completions. Well results continued to produce 30% or better than our base design wells, and given the performance, we are transitioning to higher-capacity lift to allow the wells to produce at their full potential. We also plan to complete certain wells with lower-cost sand, which results in savings close to $1 million, and can significantly improve economics in certain project areas.

Our early read-through for our 2015 plan would have us continuing to complete wells with more intensive fracs, as we will likely complete north of 50% of our wells with either slickwater or high-volume proppant. Obviously, this drives per well cost up, but we expect overall well economics to improve from these wells.

Finally, 2014 has actually been an extremely helpful year for Oasis. We have made significant progress in better understanding where the lower benches of the Three Forks works and where they don't. We have also made significant strides in full-field development, as well as enhanced economics the optimizing frac techniques. Ian has also better identified where we have opportunities to improve our existing infrastructure that will drive better cash margins.

All told, I'm pretty excited about our outlook for 2015 and 2016, especially given the great people at Oasis and our great position in the heart of the Williston basin. With that, I will turn it over to Michael.

Thanks, Taylor. In his remarks Taylor discussed third-quarter production, which will directly relate to lease operating expenses. In the third quarter, LOE per BOE was higher than expectations, in part due to lower production but also due to infrastructure. We had some operational issues on some saltwater disposal wells in systems, including a lightning strike on a disposal site that increased operating costs. We recognize that we are a bit behind where we thought we would be at this point on saltwater disposal infrastructure. We are only flowing through pipelines approximately 40% of our saltwater compared to expectations of just over 50%.

We also had a number of saltwater disposal wells that were delayed into early 2015. Recently we've resolved some of the issues and are starting to flow higher volumes through the pipeline. While we expect LOE to reduce throughout 2015, we are increasing our full-year 2014 LOE guidance to $10 to $10.50 per BOE. Ultimately, we expect to be up to reduce LOE back into the $9 per BOE range when we get infrastructure more fully built out.

We recently increased our borrowing base to $2 billion, which gives us $1.7 billion of liquidity. As we think about 2015 capital expenditures, as Tommy mentioned earlier, clearly we have not finished our full budgeting process and we will come out with official 2015 guidance in normal course at the beginning of next year. However, given a rather volatile crude price environment, it might be helpful to review our thoughts around how we think about capital.

First, we are in a great position. Given strong liquidity and balance sheet and a resilient asset base which has low breakeven economics and is essentially all held by production, Oasis has ultimate flexibility in future capital programs. WTI has been pretty volatile of late, but it is helpful to remember that a $80 WTI oil price is still a good price for us. In fact, our inventory of 3,600 gross operated locations is built off an $80 per barrel WTI price, and up until 2014, up until this year, that is what we budgeted.

That said, we also have meaningful hedges in place for the fourth quarter of 35,500 barrels of oil per day with an average floor in excess of $90 WTI, and 32,000 barrels of oil per day for the first half of 2015 with a floor of approximately $88 WTI. When we think about 2015 in light of current oil price environment, I don't think it's dissimilar from what we've said in the past.

We're definitely a larger Company now, running 16 rigs with a capital program this year of just over $1.4 billion. If oil prices stabilize above $80 WTI oil price, you can see us continue with a capital programs similar to the $1.4 billion range, maybe a bit higher or lower depending on how much above $80 we are, which will continue to drive a 20% to 30% growth rate.

In a sub-$80 WTI environment, you will likely see us further contract activity to the core or deeper parts of the basin where our wells have the most price resiliency and where we have the most mature infrastructure. As we contract to the core areas, modestly outspend our cash flow and preserve balance sheet strength, we will still deliver strong growth in this case in the mid-teens to low 20s. If you start to see a $70 WTI oil price or below, we would likely live within cash flow and deliver flat to modest production growth.

Obviously, service costs will not stay where they had been if we sustain at lower oil price environment, and that plays into our analysis as well. In each of these cases, based on our move to development, results of the higher intensity completions and the maturity of our infrastructure, we expect to be drilling more wells in the deeper parts of our acreage position in 2015.

Oasis is well positioned to continue to perform in lower oil price environment, and we will continue to be mindful of our growth rate and the strength of our balance sheet while maintaining the ability to celebrate our top-tier assets if the conditions warrant. With that, we will turn the call back over to Kate to open the lines up for Q&A.

(Operator Instructions)

Ryan Oatman, SunTrust.

You guys have done a great job driving down well cost over the past few years. And now you're experiment with greater frac intensity drilling and completing these higher-cost wells with the goal of higher returns. I was wondering how you think about responding to the decline in oil prices and the service environment? Is it tougher to decrease costs on these new well designs, or do you feel like you can really attack the cost on these new wells just as much as you would if you were still at that $7 million, $7.5 million well design?

Ryan, we really approach it the same way as we did with our typical hybrid completions that we developed over the last few years. The first step for us as we've gone to doing these higher-intensity completions is to do a consistent completion across a broad area so that we know we're getting a similar test. And once we've got that and understand what the response looks like to the rock in each of the areas, we then really start to take a step of how can we really reduce the well cost?

Like we've talked about in the past, some of the big drivers for slickwaters, one that we're looking at is proppant. Can you use sand instead of ceramic, because on the completions right now we're using all ceramic for the slickwater jobs. Another one is water, getting very low-cost sources of water and then having effective way to handle it to dispose of it as well. We will attack and we think we will get the cost down. It is first understanding where these stimulation techniques work, and then working the cost down.

It makes sense. And I appreciate the parameters and the thought process around 2015. You preempted a fair amount of my questions there. On the infrastructure side of that equation, what level should we think about there for a base program, and how are you thinking about the gathering on the assets that you acquired last year? Do you build that infrastructure out yourself? Do you think somebody else could do it better? Do you bring in a partner? How are you thinking about the infrastructure spend? You guys addressed the drilling in a pretty direct manner.

Capital program for next year on structure, you can think about the base level program still in that $50 million to $60 million neighborhood. On the infrastructure on the assets that we acquired, we are moving down a path on that. We're well down the road on getting that infrastructure in place by the end of next year, as we've discussed. Right now we're not talking about exactly how we're going to get to that.

Okay, that's helpful. I'll hop back in queue.

Michael Hall, Heikkinen Energy.

You guys have done a good job, I think, of communicating the potential impacts around these higher intensity completions. As you said, the data as it comes in continues to bias you to doing more rather than less of that. In the past you have been a little maybe hesitant to comment on EUR impacts, just given some of the data was third-party and wanting more time with you all on your own data. Any updates on that front as it relates to potentially EUR impacts? Are you seeing any signs that these higher intensity completions are not improving EUR? And how does that play into capital efficiency as you look to 2015 and a more [tore up] program?

Michael, the results so far on average, we continue to see the wells outperform over time, which would, if they continue on that trend, would lead you to believe that you're capturing unique reserves. So we look at it, the economics, from the standpoint of both a reserve add-in and from an acceleration case. And in most of areas in either scenario, the economics justify the incremental expenditure.

It's going to take us more time to get -- to really make a call on how much is incremental reserves. It is probably some component. At the very most it's 100%. It is likely somewhere in between, but we've just got to do more work in looking at the well results, get more pressure data, do more modeling to get a better handle on that.

Michael on Page 7 we talk about, in the updated presentation, we give you some data on uplift by some of the geographies. It is in the White unit we are in 40% to 50% up; Indian Hills, over 35%; Montana's actually the lowest, probably the place where we have the most cost optimization work to do, but Montana (multiple speakers) to 40% up.

Are those improvements -- is the trajectory of those improvements changing at all, I guess, over time as you are looking at things? Or is that -- are those generally pretty consistent over time?

It depends on the well. It's a variable, but on average they continue to outperform.

Okay, fair enough. That's helpful, thanks. Last one on my end --

Michael sometimes, like the Briar unit is much higher than that. So there will be places where you may see results that are better than what we show on Page 7. It just depends on where you are.

Makes sense. It's a big basin. Thank you for the color. I really appreciated the various scenarios you outlined around 2015. I think that is helpful in shaping expectation. As you talk about more focusing in in the lower oil price environment scenarios on the thinner the basin, roughly how much of your activity are you talking about being focused on that deeper, presumably Indian Hills area, just proportionally relative to the total budget just over there?

For 2015?

Yes.

I don't know that we have an exact answer yet, Michael, but I think in every case that I laid out, you're going to have a bit of contraction to the core. Part of that is as we move to development mode you are going to have more concentration, just because you're in that more full-field development type scenario. Two, our infrastructure is, call it the most mature in those areas, and we've talked about how important that infrastructure is. Three, we've got a lot of data on the higher intensity fracs in that area. And obviously it's the most price resilient. And then four, even in that high case that we talked about keeping capital flat, as we move to more high intensity fracs obviously they cost more money. So that probably means that we will drill less wells, but still have very good performance based on having that higher intensity fracs.

Yes, makes sense. Okay, great. I appreciate the color. Thank you.

Tim Rezvan, Sterne Agee.

I had a question. I appreciated the overview of the issues related to forecasting and thinking about growth going forward. You mentioned taking a more conservative view, but what gives you the comfort that the challenges you've had in recent quarters are now fully behind you, barring the weather issues that typically arise?

They're not -- we wouldn't even characterize at this point that they're fully behind us. In fact, we've talked a lot about infrastructure, and we've got a fair amount of work to do there. Michael talked about some that we've gotten wrapped up here in 3Q and 4Q that's helping us out on water disposal. But we've got quite a bit of work to do 4Q, and really for all of 2015 to get ourselves in a position where we are able to capture the majority of our produced fluids, oil and water, and then also our reduced gas.

As we go forward, that's why we projected a bigger percentage of production that is going to be, we'd call downtime or off, because you've got more exposure to that. Any time you get a road closure right now, it tends to have a little bigger impact on us because we're not capturing as much as we want with our infrastructure.

Tim, I think you're seeing all of that in -- you look at our fourth quarter guidance range, and you will see that we have a higher percentage of downtime baked in there as well as you also see that we have 15 completions that we're moving into the early part of 2015. And that's part of making sure that we have the right timing associated with what we've seen in the first couple of quarters of this year.

Okay, that's helpful. One more question. You talked about rig activity in different commodity price environments. What happens with your frac spreads in a $70 price? Do you lay those down? Would you look for third-party wells to complete?

Even at that lower pace of activity, you're probably running [north] of 8 to 10 rigs, something like that, be more around a well count. But there's enough activity there where you can support the frac spreads. We would be doing closer to 100% of the work whereas currently we're doing more like 30% to 40% of the work.

Okay. That's helpful. Thank you.

Dave Kristler, Simmons and Company.

Just thinking about the optimization of completions and 2015 guidance. As you guys think about how you're planning that out, what types of, I don't want to -- I feel like I'm backing into how high are the EURs going up, but what EURs are you using for your 2015 planning? In other words, are you using current EURs and there's upside to what happens with optimized completions, or how should we think about that gradation?

I think at this point, Dave, it is one of the outstanding items that we have is, is what of that do we factor in. And that's all part of the process, which is why we don't finalize it until the end of the year. We've got a lot of moving parts right now that include what do we think well cost will be in this environment, how much uplift do we get, or how much of this uplift do we factor in. There's just a whole bunch of moving parts. It's hard. It's not a good answer, but it's hard to tell you that at this point.

I guess what I'm going to back into is, how conservative can we be thinking about when you do outline your 2015 budget? I would speculate you're going to be closer to your existing EURs than anticipating what these wells can do, given the comments that you guys keep saying, it is still pretty early days.

I think that it's, to plan with current EURs with the kind of uplift that we've got in capital is unreasonable, but we will probably hedge a bit against going all the way to really bumping the EURs way up, just to make sure that we can hit our projections.

I appreciate that. I'm sorry for pushing so hard on that. I'm just want to get a handle on it. Then just thinking about tying in gas in general with production growth in the Balkan, are there any issues as people are tying into meet the environmental regulations with third-party processing. Is there sufficient processing capacity? Are you guys making sure to lock down specific contracts with that? Or any kind of color around the contractual obligations you are thinking about there.

Dave, obviously gas infrastructure is incredibly important. You mentioned the regulations, and those are kicking in here, and obviously we're moving to where we are going to flare less and less over time. If you look at where we've been, we've been what we feel is way ahead of the game on the gas infrastructure side in the basin, which has been a good thing. We have 96% of our wells connected to gas infrastructure. But as you saw in the third quarter and what Taylor mentioned, is that sometimes even if you are connected to gas infrastructure, you may still have issues with that infrastructure being full or the plants being full. So we work very closely with our third-party providers on that front to try to make sure that we have -- that they have a clear view on what our plans are and trying to get in front of it.

Obviously, you do have hiccups because it is tight in the basin all around, especially in certain areas. But we're doing our best and we will continue to work on that infrastructure to make sure that we have that availability. Once again, we're in very good shape from the standpoint that we've got -- given that our wells are in the heart of the basin, we've got most of our wells connected to gas infrastructure. Now it is just making sure that infrastructure has the right capacity.

Okay, appreciate that. Just one last one, and I apologize if I missed this. I t was talked about at the beginning. But looking at your 2014 CapEx, obviously there was pretty decent uptick in the third quarter, but it looks like you're maintaining your 2014 CapEx guidance. Is that also contributing to the decision to push some of these completions into 2015, or am I off-base on thinking about CapEx for 2014?

I don't think that CapEx -- I mean, that's not part of the decision. That is more of a timing thing and making sure that we can get those [wells] online, kind of like what we talked about before. From a CapEx standpoint, I think we're holding to the 1425. It can be pressured up just a little bit based on some of these higher stage completions that we are doing in the fourth quarter, but we should be in and around that same range.

Remember as Taylor mentioned, even though we've got --we had initially 2005 wells to be completed, and that might be more like 190 now. A lot of those 15 wells that are pushing into the first quarter, a lot of the capital will still be spent in the fourth quarter. We're not moving those completions out into the first quarter just from a capital standpoint, because a lot of that actually work will be done in the fourth quarter.

Just to add to that, Dave, it is really around -- it is operational. A lot of those wells are on pads, and we can't get them completed in time. They're just pushed out a bit because of the pad operations.

Okay, great. I really appreciate the incremental color, guys. Thanks so much.

Michael Rowe, TPH.

I think you hit a lot of my questions, but I wanted to maybe come back here to the balance sheet for a second. I guess you mentioned and have highlighted that you have got a lot of liquidity here and feel good about your balance sheet. But just wondered if you could maybe characterize where your balance sheet is today, and if you have any goals in 2015 in terms of managing your credit metrics, or is that not really the way you think about it?

Obviously we think a lot about our balance sheet and where we are at. We have talked about that coming out that the acquisition last year. We did leverage the Company up a little bit more. We like to target a debt-to-EBITDA metric of around 2 times. We're more in the 2.5 range, and a higher oil price, obviously we delever very quickly. As we are in a new world here in the last, call it 1 to 1.5 months with where oil prices and we think about that, that is certainly one of the things that drives our decision from a capital program standpoint.

There's obviously many things that go into that, but that is certainly one of the important critical items. As you see in each of these cases that we lay out, obviously if you are in a sub-$70 oil price and you're drilling within cash flow, leverage metrics in the meantime will go up a bit just because of oil pricing and EBITDA going down. But you're maintaining your aggregate debt levels at that point. We feel comfortable in that scenario.

Two, in more of a sub-$80 level you're going to contract your capital program to be under what we're currently spending for this year. You're going to be out-spending cash flow by a little bit, but you'll still have pretty good growth rates on top of that. So once again, you should be able to at least hold credit metrics flat in whatever oil price environment you are, if it's called a flat oil price environment.

That is why we also said that in an $80-plus environment it's going to depend on how much above $80 you are, we will start to meter that capital program going forward. Obviously balance sheet is an important piece. We think we're in a strong position right now to at least maintain credit metrics in a period of lower oil prices.

Okay, that's helpful. The last question really relates to the well inventory that you all have. You mentioned earlier that you've changed, I guess, the economic bound of the lower Three Forks, but wasn't really baked into your inventory in any material way. I guess I was wondering, is there anything else that you think could change your inventory to the positive side, as you've done more deeper Three Forks bench testing in the deeper parts of the basin?

You hit on one of the things that could have an impact, and that is the deeper benches, and specifically the third benches included in any of our inventory. And the graph in the presentation we show a number of third bench tests that are within our type curve range. So we think there's quite a bit of upside there to adding third bench wells at some point in the future.

Ron Mills, Johnson Rice.

Taylor, I got interrupted when you are talking about the third-quarter impact. You totaled 2,500 barrels of production impact from the various items. I got the 700 from the infrastructure. I think 800 from the increased density on the DSUs. And 600 from the impact from the lower Three Forks and North Cottonwood. What was the delta, the last 400 BOEs per day?

That was flaring. Specifically, it was around some of the bigger DSUs. Hagen Banks was an example of that where we had a lot of concentration of gas and we didn't have -- our third parties either didn't have enough capacity, or in some cases didn't have lines hooked up in time. So we ended up -- while we account for some flaring, we ended up flaring more than we would have thought. And that was 400 barrels equivalent.

Okay, great. Thanks. When you talk about the interdependency of pad development operations, I assume that's related to the increased density per DSU. I think you had a similar instance last quarter. As you look forward and increase your increased density, what should we -- or how can you go about better planning for that increased density drilling, and maybe better managing the growth expectations?

One of the things, Ron, as we go to these higher density DSUs, the planning and execution piece is just huge. So one, is really effective planning of each of these steps and working on the DSU. And then really good execution of those things. Now, when you do have problems, because it is going to happen every now and then, a really important part we've seen is to have a plan around that.

That plan may be that you have a well that's an issue. Rather than trying to fix it right now, you may leave it for a while and come back later. But having a plan about how you are going to attack that, amongst our whole team is -- we've identified as one of the things that's going to be really important to execution on those DSUs.

Keep in mind, Ron, that while we focus a bit on it, this one Mallard unit, I think there were 11 wells, something like that, and when we look at our graph of downtime relative to what production capacity should be, we had four months. So while it seems like we talk about it a lot, it's four months of a time where we're trying to get everything lined out. And the first two months of the four months, we were only producing at about 20% of capacity. The second two months we were producing at 40% to 50% of capacity.

When one of these things gets upside down on you, there are lingering effects, which is why you are dealing with it for four months and we're still not up to 100%. But if you look at these other things that we've done at Hagen Banks or the White unit, we've done a lot better from a process standpoint on those. It's just that, boy you get one of these thing that gets upside down on you, it is 11 wells out of 60 wells that you bring on in a quarter, it matters. Hopefully, that's the extreme -- the one extreme example.

It sounds like some of that was infrastructure related and some was just -- I mean, things happen when you are completing that number of wells. Is there a way to handicap how much was waiting on infrastructure on some of these higher density pads versus experiencing just some issues on a well here or there?

The ones we talked about, 800 barrels a day, was primarily hiccups around operations in a pad. The thing, Ron, that I would add to this, though, the second part that is really important is having flexibility so you've got enough additional inventory and ready locations and ready completions where if you do have a problem on a spacing unit or on a set of wells that you've got a backup that you can go to that is a like set of completions.

As we accelerated from 9 rigs to 16 rigs, we were in a situation where we didn't have as much pad and options outside of the planned program. So when we did have a hiccup we didn't always have great alternatives. We're building ourselves into a position where we've got all those alternatives. That's a big part of the program for fourth quarter, then going into 2015 is a lot more flexibility.

Is that addressing what you talked about last quarter of when you had that hiccup that you ended up taking a rig over to Montana, which is lower productivity, and then in this quarter taking the rig up to North Cottonwood and delineating the Three Forks?

Exactly. When you have to move a rig or rigs out of an area that has higher EURs and you plan that in your volumes, and if you have got to move to low EURs, that is not a good outcome for you. Having that flexibility around enough of those like type of completions so that you've got alternatives.

When you look at your -- the Indian Hills or the South Cottonwood, or even Eastern Red Bank, if you look at your acreage position, how much do you think is in those areas where you would have similar type opportunity sets and at similar levels of potential? And how many of your rigs do you think you'll run in those deeper, better parts of the basin versus moving over towards Montana and North West Red Bank, et cetera?

Just from an inventory standpoint, you've got about 26% of your inventory in the highest -- this is a table in table in the back of our investor presentation on Page 21. You've got about 26% of that inventory is in the highest EUR area. So you've got quite a bit of that inventory to go to. Now like Michael talked about, in terms of what the concentration of rigs are next year in those higher EURs areas, we're still working on that. But it is greater than 50%. It maybe somewhere 50% to 75%, or maybe even a little higher. We will just see.

Ron, you may not have had a chance to -- again, we throw a bunch of stuff at you. You may not have had a chance to look through the presentation yet, but if you just look at Page 6 where we tell you were all the rigs are, what you will see is, is that effectively currently they're all on the very south end of Cottonwood, Eastern Red Bank, and then the guts in Indian Hills. We've still got two over in Montana. But you can see, if you just compare this presentation to the previous, how that contraction has already started.

John Nelson, Citigroup.

I just actually wanted to follow up on the last comment about building alternatives. And does that mean that you are saying steady state moving forward, we should think about you carrying a higher drill [billing] completed inventory? And how should we think about those levels moving forward, or is that not maybe what you were trying to say?

It is probably less around wells waiting on completion. That's going to be driven more by the amount of wells that we have on pads or in DSUs that you've got to complete all at one time. That is why you get this lumpy nature of wells waiting on completion. Was really talking about having more inventory of things that are ready to drill. So if you have a problem with a DSU that gets pushed back, you've got another set of -- another DSU or a set of wells that are like in nature that you can go and drill. So it's permitted wells and locations built that give you alternatives.

That a helpful clarification. Thanks for that. I thought it was helpful when you guys walked through the variance on why production came up short for the quarter, and also talking about how you were going to increase downtime or shut-in expectations going forward. Obviously, with your stock where it is, I'm sure you don't want to get in the practice of putting out year-end exit rates. But if I follow that logic, you should see a pretty strong balance as we get into 1Q. Does that look similar to what your guys model are, or would you care to comment at all on where production expectations have moved down to relative to what you guys see?

Probably a little bit early to talk about first quarter. Or Michael talked about in an aggregate sense what we think -- how we think about 2015. But as I mentioned, you are watching prices here, trying to get a better gauge on service costs. And there's just a lot of moving parts at this point to start trying to project specific numbers for 2015, let alone first quarter. It's just a lot of stuff moving around.

Okay, fair enough. Then just the move up in expected shut-in times, I think around 8% guys said. Is that how you guys are thinking about moving forward, that's a good number to use, or is there anything specifically in 4Q that's caused that shut-in and downtime number to be higher?

I think it's 8% to 10% for first quarter and probably going into early next year, and then if we see a point at which that meters as we get more structure in place and we are in a better position to bring that down, then we will let you guys know.

Gail Nicholson, KLR Group.

With the current oil price environment, do you have any preference between pipe versus rails from a takeaway capacity standpoint?

Gail, I think that you're going to continue to -- look, we've got flexibility in our system, on our gathering system to be able to go to both pipe and rail. So we certainly have a mix of both. That's driven largely also by the spread between, call it Brent or coastal prices versus WTI as opposed to the straight up [advria] price of WTI. Here over the last few months you've had a bit of a narrower Brent or coastal market to WTI differential, which tends to push you a little bit more towards pipe. But that mix I think will continue to change. We still do rail quite a bit of crude, but that mixture changes really on a daily and monthly basis.

The great thing is that you have more and more infrastructure that's coming into the basin. We continue to see new rail facilities that are coming online. We're seeing significant amount of pipe that will be coming in over the next two to three years. A lot of open seasons out there. So that obviously is all very positive from a producer standpoint to have options going forward.

Looking at the higher proppant jobs as well as the slickwater, have you seen any difference between those performance, or have they both been in line and outperforming expectations with current curves?

Most of the tests that we've done so far have been with slickwater. We've got a handful of the higher proppant stimulations, but they're earlier time. But both of them in general have shown out-performance. We just don't have as much data on the high prop at this point. We've got quite a few of them that are currently being completed and will come into play in the fourth quarter and first quarter. So we will have more data as we get into early next year.

This concludes our question-and-answer session. I would like to turn the conference over to Oasis Petroleum for any closing remarks.

We recognize the third quarter has presented challenges, some internally imposed and some externally imposed. In light of that, we have level set our expectations and feel like we're in good shape moving forward. We have an excellent asset base and the operational and financial capability to execute on it. Thank you for participating in our call today.

The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.