Chord Energy Corporation (CHRD) Q4 2014 Earnings Report, Transcript and Summary

Good morning. My name is Katherine, and I will be your conference operator today. At this time, I'd like to welcome everyone to the Fourth Quarter 2014 Earnings Release and Operations Update for Oasis Petroleum. Please note, this call is being recorded. [Operator Instructions] I will now turn the call over to Michael Lou, Oasis Petroleum's CFO, to begin the conference. Thank you. Mr. Lou, you may begin your conference.

Thank you, Katherine. Good morning, everyone. This is Michael Lou. Today, we are reporting our fourth quarter and full year 2014 financial and operational 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 February investor presentation, which you can find on our website. I'll now turn the call over to Tommy.

Thanks, Michael, and thank you for joining us today as we review 2014 results and roll out more detail around our 2015 plans. Oasis has delivered substantial growth since our IPO, growing from about 5,000 Boes per day in 2010 to over 50,000 Boes per day in the fourth quarter of '14. During this time period, we capitalized on the strength of oil prices, which allowed us to preserve our extensive acreage position and provided the flexibility to be aggressive in testing well spacing, completion techniques and the prospective-ity of the entire Middle Bakken/Three Forks section, and at the same time, the ability to expand our acreage position to roughly 500,000 net acres within the Williston Basin. Now as we operate in the current challenging commodity price environment, we will focus more of our -- on our financial health while maintaining our operational momentum with an eye on accelerating activity when commodity price improves. While we did encounter some challenges as we transitioned to full field development in 2014, we did achieve several key milestones: we increased average daily production 35% year-over-year to 45,656 barrels of oil equivalent per day; we completed and placed on production 195 gross operated wells, including 48 operated wells on the fourth quarter; we increased total estimated net proved oil and gas reserves, excluding Sanish, by 24% to 272 million barrels of oil equivalent with approximately 87% oil and 54% developed; we ended the year with a lease hold position of approximately 505,000 total net acres; we increased revenue by 22% to $1.4 billion, and increased EBITDA by 16% to $953 million; we completed the sale of our non-operated Sanish position for $325 million, which included a $187 million gain on sale; and we ended the year with total liquidity of just over $1 billion. Looking to 2015, we are rolling out a capital plan totaling $705 million, which is 12% lower than the plan we rolled out in early December 2014, due to lower commodity prices and the associated decrease in well costs, but will still allow us to keep our year-over-year volumes relatively flat. Throughout the year, our capital will be focused in Indian Hills and South Cottonwood, where we have the highest well productivity, the best predictability in results, the most established infrastructure and the best resolution on full spacing unit development. Within this area, we have over 8 years of highly economic inventory at a $50 to $60 WTI price at the current activity level. And given that our acreage across the basin is effectively all held by production, we also have tremendous option-ality through a great position outside of these core areas that we've made extremely economic by lowering well costs and optimizing completion techniques. Before I turn the call over to Taylor, I'd like to highlight 3 areas where we have really advanced how we think about developing our asset and our plans going forward. First, we completed 39 high-intensity completions in 2014, and early results look very encouraging. While we tested multiple techniques in an effort to enhance returns, our analysis of performance is pointing us towards focusing our efforts in 2015 on high-volume proppant and slickwater jobs. Second, we rolled out -- when we rolled out our 2014 plans to you last year, we highlighted that we were focused on subsurface well density, which included both down spacing tests and further delineation of the Three Forks benches all the way through the section into the lower Three Forks. In line with our plans, we completed about 30 lower bench Three Forks wells across our position in 2014 and conducted a significant number of well density and interference tests. This work has changed the way we think about how to most effectively develop a DSU and our overall inventory. Taylor will go into more detail about that in a moment, but the net effect is, is that our Middle Bakken inventory went up while our Three Forks inventory went down. In fact, in the shallow parts of the basin, we think that we can effectively drain the Middle Bakken/Three Forks resource through wells placed for the most part in the Middle Bakken. Third, OWS, our in-house well services company, and OMS, our in-house saltwater disposal business, continued to exceed expectations. These 2 businesses continue to add significant value and will prove resilient during the current environment and will provide us with a competitive advantage. We're exploring opportunities to finance OMS with external capital. Because the asset provides so much value to our E&P business through ensuring uptime and lowering operating costs, we continue to want to maintain control of that business. We don't -- we do not intend to sell it, but we believe that there could be the opportunity to use the cash flow stream and in-house expertise to either de-lever the Oasis balance sheet or fund future capital, particularly on our Wild Basin project. When we did the large acquisition in 2013, we noted that the new position was infrastructure-light. We've been working on the right plans for this asset, particularly in the Wild Basin acreage block, which is included in what we broadly call Indian Hills. In our current 2015 capital plan, we're spending approximately $45 million, primarily on right of way and initial work on the gas plant for Wild Basin, and expect expenditures for the Wild Basin project to total, for the combined years 2016 and '17, between $140 million and $150 million for the SWD system, gas gathering, crude oil gathering and the remainder of the gas plant. Fourth quarter 2014 annualized EBITDA for OMS was about $32 million, and we expect this to grow in 2015 and 2016. With that, I'll turn the call over to Taylor.

Thanks, Tommy. During the second half of 2014, we began to ramp up high-intensity completions, and as a result, we were able to complete about 20% of our wells using slickwater or high-volume proppant during the year. Our focus in 2015 will be on Indian Hills and South Cottonwood, where we now have 20 producing high-intensity completions. We also have nearly 20 producing high-intensity wells outside of our 2015 focus area, spread across our position, which we will continue to monitor. As you can see in our slide deck on Page 11, these wells continue to outperform across the position. For example, our Montana Bakken wells are exceeding offsetting hybrid wells by approximately 40% and Red Bank and Indian Hills wells are outperforming by approximately 30% to 50%. In South Cottonwood, Bakken wells are performing about 40% above offsetting hybrid wells. The White Unit located in Indian Hills, which was our first unit combining both slickwater and spacing density test continues to outperform both our type curve as well as our direct offset wells. As you can see on Slide 10, both the Bakken and first bench of the Three Forks are outperforming offsetting wells by nearly 80% and 70%, respectively. This has given us confidence to expand the use of these techniques across our Indian Hills and South Cottonwood areas in both the Bakken and the first bench of the Three Forks. While these high-intensity wells generally cost $2 million to $2.5 million more than a hybrid job, early results indicate these wells are benefiting from increased early time production, and we expect to see EURs grow as a result of these types of jobs. With that said,, we will be completing 60% of our wells with slickwater and high-volume proppant in 2015. Next, not only did we spend a lot of time testing different completion methods across our position, we also invested heavily in testing and understanding the fracture patterns and drainage patterns associated with down-spacing test and lower bench well test. Based on well results in our subsurface modeling, we have increased our confidence in tighter Bakken spacing. Additionally, one of our objectives going into 2014 was to push our understanding of the limits of the lower benches of the Three Forks across our position. We completed around 30 wells in the second and third benches. Some areas have shown encouraging results while others have been more challenged. As a result, we have decided to adjust our inventory in the lower benches to reflect our current development plan, which now includes tighter spacing in the Bakken and first bench of the Three Forks. We believe that we can more effectively drain reserves by drilling more wells focused on the Bakken in the first bench, which will still capture reserves from the lower benches. So as you can see on our Inventory slide in our presentation on Page 8, we have provided our review on spacing per DSUs by area. On Slide 9, we highlighted our remaining inventory in Indian Hills and South Cottonwood, the area where we are counting approximately 15 wells per DSU. We have 825 locations remaining, of which 124 wells are in the lower benches of the Three Forks. Excluding the lower bench wells, the count of 701 wells would provide an inventory of more than 8 years at our current completion pace of 79 wells per year. Like we have highlighted in the past, we are extremely encouraged with our position in the Williston. With another 2,221 wells outside of the deepest part of the basin and with our advantaged cost structure, including OWS, we feel confident in the value for our premier position over the long haul. Since the inception of OWS, we have invested $73 million into the business. To date, it has generated $174 million in gross EBITDA, including $88 million of EBITDA in 2014 alone. Not only does OAS allows us direct cost savings in the form of capital reduction, which totaled $57 million in 2014, it also ensures quality of service and provides transparency into the market with regard to service cost inputs. Since OWS now completes substantially all of our wells and we have shifted toward high-intensity fracs, the savings provided by OWS is expected to grow on a per-well basis. In 2015, a portion of our non-E&P capital will be allocated to OWS to add pressure pumping capacity. This will allow us to complete more high-intensity wells in-house with the goal of driving down costs and increasing well performance. On the OMS side, we continue to invest in our salt water disposal business, which produced approximately $32 million of annualized EBITDA in the fourth quarter. Michael will be giving more color on this in a moment, but we continue to expect this to grow into 2015 and 2016. I will now turn our attention to our overall 2015 development plan, which is very similar to the preliminary plan we articulated in December of 2014. As we highlighted, we were going from 16 rigs down to 6 rigs by the end of March. We are ahead of schedule on the rig drops and are currently running 5 rigs. We maintain the flexibility to further increase or decrease our capital program as the year progresses should conditions warrant. We are also tightening our guidance a bit on the CapEx side and now estimate that we will spend $705 million, with $565 million of that allocated to drilling and completions. This will allow us to complete 79 gross operated wells and 65.9 net operated -- non-operated wells throughout 2015. As we progress into the year, our completions will be increasingly focused on the deeper parts of the basin. We ended the year with 72 wells waiting our completion, a number which has currently grown to 88. Like we discussed before, we plan delaying some of the completions and we'll manage the exact pace of completions this year based on the operating environment. I'd also note that the majority of our acreage is already held by production so there is no need to allocate rigs to hold acreage during the year. With that backdrop, we have provided a guidance range for the year of 45,000 to 49,000 barrels of oil equivalent per day, which still delivers flat to 7% growth compared to 2014. We are also tightly managing cost inputs into the business -- in 2015 as we highlighted in our press release. I will turn the call over to Michael.

Thanks, Taylor. As you know, we are extremely focused on managing the business based on the current oil price environment. As Tommy and Taylor mentioned, we are focusing our drilling and completions activity in the areas where we have the best economics, as well as the infrastructure in place to enhance uptime performance and lower operating costs. We have a strong hedge book with over 50% of our expected 2015 production hedged with average floors of over $88 per barrel. We are also focused on managing our balance sheet during this downturn and, and it is important to note that we had approximately $1 billion of liquidity as of the end of 2014. While our total borrowing base was set at $2 billion in last September, we currently expect to see some reduction in that number in our April redetermination. Still, we anticipate that the borrowing base will be above our current elected commitments of $1.5 billion, even with the banks running our reserves at a lower priced debt. Like you saw in our release, reserves were up 24%, excluding reserves from Sanish, which definitely helps support the strength of our borrowing base. Based now or 2015 capital expenditure budget that Taylor outlined, we will be outspending cash flow by approximately $100 million to $150 million this year. However, the out-spend is essentially limited to the first quarter, where we will be outspending due to the order early reduction of our program to current level of activity. 80% of our $705 million capital expenditure budget will be allocated for drilling and completions. Of the remaining $140 million of non-drilling and completion capital, $81 million is allocated to our midstream business. Like Tommy mentioned earlier we have really grown our OMS business and now have the potential it finance it to help us manage the balance sheet and fund capital associated with those projects, including the Wild Basin project. We are continuing ahead with expenditures for this project to allow us to capture the value associated with controlling this asset and ensuring that we have the infrastructure in place in 2016 when we start completing wells in Wild Basin. This asset has the potential to deliver substantial cash flow through the capture of gas and oil and the gathering and disposal of salt water. Additionally, we are continuing to invest in OMS throughout the remainder of our properties that give us short paybacks and solid long-term returns. We now have approximately 40% of our saltwater volumes connected to pipeline and expect to end 2015 with approximately 60% connected. We are also flowing about 60% of our saltwater volume down our own saltwater disposal wells, which should grow to closer to 75% by year-end 2015. As we increase the saltwater that is gathered and disposed in our system, we will continue to grow own[ph this EBITDA from the $32 million fourth quarter '14 annualized level. With the addition of the Wild Basin project profitability in the second half of 2016 and beyond, OMS is expected to grow considerably, in the next few years. As we have discussed in the past, our saltwater system investment drives down LOE and you can see that reflected in our guidance for LOE in 2015. The midpoint of our LOE guidance in 2015 is $10 per Boe versus 20 -- 10 to 18 per Boe in 2014. The guys did great job of driving down LOE in the fourth quarter to $9.69 per Boe and we will continue to try to drive down costs over time, to below that level. On the gas side, we currently have 97% of our wells connected to third-party gas infrastructure. We have worked hard to connect wells and we are confident in our ability to continue to meet North Dakota's gas flaring regulations, as well as capture and sell substantially, all of this extremely valuable resource. With regards to oil, our third party gathering system collects approximately 75% of our produced oil, which has enabled us to deliver some of the best differentials -- oil differentials in the basin, which was $9.74 per barrel in the fourth quarter. We expect the first quarter to be slightly better in the $8 to $9 per barrel range. We expect to continue to leverage the strong infrastructure position especially in the deepest parts of the basin, where we're focused in 2015. One last note. I mentioned earlier that we have a strong hedge book. As we noted in our press release, we settle and book our hedges the month following the contract. I know many people model October, November and December hedges for the fourth quarter versus what we booked, which was September, October and November. The full impact, if you drop September and add December, would be an increase to EBITDA of about $31 million. However, given our accounting methodology, you'll see the benefit of that December hedge in January. With that, I'll turn the call over to Katherine for Q&A.

[Operator Instructions] Our first question comes from Subash Chandra from Guggenheim.

Where does Red Bank fit in the development pace? And sort of, if it's infrastructure-related or price-related, what sort of price would you need to get development there? Or finally, is it just you're managing cash flows in '15 and sticking with South Cottonwood and Indian Hills?

So it's -- Subash, it's really, as you said, around managing our capital and our cash flows. And Red Bank is not at the high end of our inventory but is just the next leg down, not real far below, especially the eastern side of Red Bank. So at some point, as we go into a rebound, it's one of the areas that we'll consider going back to when we pick up the pace a bit.

And looking, I guess, at the Infrastructure slide, it looks pretty well-serviced. Is that a fair statement? And sort of that could be a quick restart on a price recovery?

Yes, that would be accurate. The infrastructure in Red Bank is really in pretty good shape.

Okay. And then my second question is, at this point, is the ceramic part of the slickwater completion, is that something you won't pursue? Or are you still pursuing ceramics?

We are, right now, at the slickwater jobs that we're pumping, most of them continue to be with ceramic. However, we have tested 2 wells with close to 100% sand and then we have some additional wells, additional 2 or 3, where we've done a combination of sand and resin-coated sand. And early time, the results on those wells look similar to other slickwater wells around them but it's very early time. These wells were completed mostly in the fourth quarter or even in the first month of this year, but we'll continue to monitor. If we do go to all sand, you could expect an incremental savings on our wells of about $1 million.

Wow! Okay.

Our next question comes from Phillips Johnston with Capital One.

I'll ask you about 2016 and a scenario where oil prices stay relatively flat. With next year's volumes looking flat to slightly down at the current run rate of activity, and just given that there's at least $200 million or so hedging game this year that aren't going to recur next year, your cash flows should decline by about that much next year versus this year, all else equal. My question is really 3 parts. First, in that scenario, would you expect to drop another 2 to 3 rigs in order to limit the outspend? Second, what would your production declines look like in that scenario? And then finally, your liquidity situation is great, as Michael noted, but what steps can you take, in addition to possibly monetizing OMS, in order to prevent your leverage ratio from increasing to uncomfortable levels in that type of scenario?

So a couple of things. One, in 2016, as we look out at it, if you assume kind of the strip prices in a $60 to $65 range, as you mentioned, with the hedges rolling off, operating cash flow will be lower. However, we do think that we can continue to maintain flattish-type production levels and spend essentially within cash flow in that scenario. A couple of the reasons why is that we are going to have kind of a full level of being in kind of, the best parts of the basin. As Tom and Taylor mentioned, we have over 8 years of inventory in that -- in those areas, and so we've got a very long inventory in that area. Two, we'll have the full benefit of cost reductions from the year as well. And so you're going to have the benefit of kind of, both those things in there. Obviously, we're also battling less production declines year-over-year, so it kind of ties into the second part of your question. But as you can imagine, without a rapidly growing program, like we've had over the last 3 or 4 years, this year is going to be more relatively flat. We'll leave this year with our base level of production declining less than, than we're entering the year. So we won't have to battle those declines quite as heavily in 2016 as we do in 2015. And then on the flip side of that, on the liquidity side, obviously, with a little bit of an outspend this year, our liquidity position is not quite as strong, but essentially is flattish from where we will be at the end of the first quarter. And so I think we'll maintain a strong liquidity position. Obviously, the company can always do a number of other things, and I'm sure all companies are taking a look at other methods, whether it's divesting of noncore assets, whether it's looking at the capital markets and a whole host of other alternatives. So unlike our -- just like everybody else, we're going to review kind of all of our -- all of the alternatives out there.

Okay. Just on that note, Michael, we've seen several E&P companies issue stock in the last couple of months or so. Is that something you guys would consider here?

Yes. Like I said, we're -- we will kind of, review all of our alternatives and take that into consideration. Clearly, based on market activity over the last month or so as well as even -- seems like the last couple of days, it's -- the equity capital markets are there. It's one of many levers that we're looking at, so we'll take that into account with kind of everything else that we've got, that we're looking at.

Makes sense.

Our next question comes from Michael Rowe with Tudor, Pickering, Holt. Michael J. Rowe - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Just wanted to see if you could provide thoughts around at what oil price level would you be comfortable laying on hedges in 2016, given low breakeven economics in your core Indian Hills and South Cottonwood positions?

Yes, Michael. On the hedge side, we've always kind of, viewed hedges as insurance, and what you'll probably see us do is be a bit programmatic in the way we're hedging. We still make good returns, as we said, at -- in the level that you can hedge into in '16, so that $60- to $65-level, you can make good returns. So what you'll probably see us do kind of over the course of the year, and this is no different than how we've been in the past, is we'll look to layer on hedges, but I don't think you should expect any big moves, one way or another, on the hedging side, any kind of quick or drastic kind of deal. Michael J. Rowe - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Okay, that's helpful. And I guess you talked about the cash flow out-spend in 2015 being weighted towards Q1. Let's talk about that just in a little bit more detail as it may be sort of, the high point of production for the year. So I guess just maybe provide a little bit more color on why Q1 will be kind of the high watermark. Is that just related to capital spending being weighted mostly towards Q1?

Yes, Michael. Just as you think about where we're at today, we've moved down to -- from a 16-rig level down to a 5-rig level. Obviously, it's taken us a little bit of time, although we've moved very quickly to that level. There was kind of, that lag effect of as you're moving that number of rigs down, you have a little bit higher activity here in the first quarter and as that drives a little bit higher CapEx for the first quarter. As you move forward, you're more in that balanced level. So we're looking at, call it, 68 completions a month. Our rig program is kind of in that same ballpark with a 5-rig schedule and so you're now kind of at -- kind of that -- this point going forward, a more normalized CapEx spend.

Our next question comes from Dave Kistler with Simmons & Co. David William Kistler - Simmons & Company International, Research Division: Real quickly, just trying to triangulate the numbers around coring up. If we look at the type curves in your core area, they're about 25% above the typical type curve. Is that the easy way to think about productivity gains in terms of on a per-well basis? Or could we see even productivity gains above and beyond that?

So just going into the core area, you get a kind of an uplift you're talking about, Dave. And then if you get a slickwater response on top of that, like we think when we modeled it at about 30%. You're going to get an incremental gain on top of just going to that poured-up higher EUR acreage. David William Kistler - Simmons & Company International, Research Division: Okay, appreciate that. And then as well as we're on the slickwater fracs and hybrid fracs, obviously, large IP uptick, a little bit more measured in terms of how you bring it up the EURs at this juncture. When do you have or when do you feel like you'll have a more definitive view on that EUR uplift?

We continue to -- as we've laid out here, we continue to look at the production increases: Substantial really across all the areas where we tested these techniques and encouraged by that. We think we need -- it's probably in the order of a year. What we're shooting for is by the end of this year to be in a position to more definitively say what that EUR uplift is. We do think there is an uplift, and right now, we range it between 10% and 30%, and we'll continue to monitor that. Mike said it, that, hopefully by year-end, hopefully we'll have a more definitive answer for you. David William Kistler - Simmons & Company International, Research Division: Okay. And then just one follow-on for that. So when we're looking at reserves that you guys booked this year, I would assume very little contribution from the potential increase of the slickwater fracs and the hybrid fracs. Is that a fair characterization? And any sense of what that magnitude might be, looking forward?

So for -- in 2014, it was a small number because it was a small portion of our overall program, so it didn't have an impact. Obviously, in '15, we're going to have 60% of our wells, will have higher-intensity fracs. Our reserves are actually done by a third-party, D&M, and I think you'll probably see, again, some component of a contribution from these wells producing at a higher rate but unlikely that full contingent. So maybe you're at that lower end of the 10% to 30%, then we'll see where we'll come out as we get to the end of the year, but still early time. David William Kistler - Simmons & Company International, Research Division: Okay, I really appreciate the added color, guys.

Our next question comes from Steve Berman with Canaccord.

I think you -- someone said earlier you have 88 gross wells waiting on completion, up from 72 at year-end, and you're going to complete 79 gross operated wells this year. How many wells do you expect to spud this year?

The spud number is moving around. We came into the year with a bunch of rigs, and we are down to 5 so we had a couple of months where we were actually running more like 10 rigs, now we're down to 5. So I think a good way to think about it, like Michael said, is we're kind of on a steady-state at this point. And with those 5 rigs, we're going to complete 79 wells with those 5 rigs. It's in the order of the same amount of activity.

Okay. And question for Michael, following up on an earlier question. On the CapEx can you give us any sort of number? I mean, how front-loaded is it going to be, either by quarter or by half, that $705 million?

Yes. I don't know if there's an exact number, but as you can imagine, as we're kind of communicating it, that $100 million of out-spend is going to be in the first quarter, so you are going to see that weighing in the first quarter. Overall, cash flow is going to be pretty flat after that, so you're going to have kind of an extra, around, call that, $100 million in the first quarter, kind of, compared to every other quarter.

Our next question comes from Noel Parks with Ladenburg Thalmann. Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division: Just trying to get a sense of something, and you've given a good bit of detail, which is definitely helpful. You were talking about the strip next to your -- looking in that at $60, $65 range. And if we think of the difference between, say, that being a steady-state going forward and maybe a skinning [ph] $10, say, on that if we have signs of better oil demand, et cetera. When you have that sort of a delta, about a $10 change in outlook, what are sort of the main effects that you have in a scenario like that? Someone mentioned Red Bank as an example of something that, at a higher price, would come back on board. Are there other similar things that are implied if we see somewhat stronger than where we are now?

I'll start and then I'll let Michael kick in. Because one of the first things we're going to think about is our balance sheet, where are we at that time. And I'll let Michael talk a little bit more about that. From the standpoint of our asset base in the other areas that we would go to, it will be a combination of -- what will be important, the combination of the infrastructure that we have in that area and then the economics of the wells. And a continued improvement in our well costs, as we continue to drive that down, the places that point to are -- one area we call City of Williston, which is north of Indian Hills, which -- has strong economics. We've talked about in the quarter, most of what we're doing this year is Indian Hills and Wild Basin going into '16. We also have a substantial amount of inventory in South Cottonwood or Alger. And then the next areas will probably be East Red Bank and Hebron.

And the other part of that, we obviously have a lot of operational flexibility. Kind of -- Taylor kind of mentioned we had just over 70 was waiting on completion at the end of '14. We'll end this year probably in the same ballpark. You always have the operational flexibility of going either up or down pretty rapidly, especially when you have a nice backlog of wells waiting on completion. So it gives us a lot of kind of timing flexibility rather than having to increase rigs and wait for that cycle to get that production response. So good flexibility from the operational side and how it affects production as well as cash flows. And then as Taylor mentioned early on, the other thing that we'll think about is the balance sheet. We'll continue to think about whether or not it makes sense to increase the program or to repay debt in those situations. But obviously, a $10 move in oil price would be very significant for us from a cash flow perspective, so we'll just determine where we'll use that excess cash flow. So the good thing is that in that circumstance, based on kind of our current program, you're going to be cash flow positive in a pretty big way in 2016, so you have a lot of different things that you can think about. Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division: Great. And one other thing, in the Williston as a whole, of course, the public company has, in the past, disclosed a lot about their thoughts strategically and in terms of activity. Can you give a feel for what you perceive is going on with your private peers? There are some large ones in the basin, I'm just -- I guess I was thinking about, I don't know, are there win-win-type opportunities, perhaps, on acreage swaps in decent scale, just because people might be in a similar area but could have yield very different balance sheets and so forth.

Yes, I think it's a few things there, Noel. I think, one, what we're seeing is that while you have these big drops in rig counts by the publics and everybody can kind of, get their head around that because you have numbers associated with it, I think what you'll see with a lot of the private guys is that it'll be even more significant and -- for privates and even some of the much smaller publics effectively, going to 0, but it's always -- you don't get into the public domain, you got to go over to one of the reporting services to figure out exactly who's dropping what. But with a lot of the smaller guys, like I say, they'll go to 0. And I think you will see, as everybody focuses on being more efficient in all areas, you will see people swapping acreage to be efficient. But we've done that on a routine basis for the last several years. We're swapping acres all the time to get efficient. Yes, we see more or less of it this year because of the operating environment, kind of hard to say, but not out of the realm of possibilities. In the past, most of the swaps that we've been doing were with the bigger guys. And so you may see more with the smaller guys in this environment.

Our next question comes from James Spicer with Wells Fargo.

In some of your comments earlier, I think it was Michael, you mentioned that your base level of production decline next year is going to be lower than this year. Can you just quantify where you are this year and where you expect that to go next year?

Yes. So this year, your base level decline's probably in the 35% neighborhood. By the end of this year, you're going to be more like in the 25% to 30% neighborhood.

Okay, great. That's helpful. And then secondly, can you just comment a little bit how you think about appropriate levels of leverage and absolute debt in a lower-price environment? And if there are specific metrics that you're going to be targeting here over the next year or so? For example, absolute level of debt reduction or anything like that?

It's a good question, James. What we said is that we're always looking at how we can manage to more like a 2x debt-to-EBITDA level or better. Obviously, we're a little bit higher than that now, but always looking for ways to get back down into a level that they feel a little bit more comfortable. And so as we kind of mentioned in a previous question, we're going to look at kind of all different opportunities to make sure that, that leverage level is in an appropriate level. Obviously, with higher oil pricing, if you get to a higher oil price environment, that's going to naturally help as well. So it's a balance of a number of things that we're going to continue to watch.

Okay, I got it.

Our next question comes from Don Crist with Johnson Rice. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: It's Ron. Question, you all have talked about having a similar number of wells in backlog versus -- at the end of '15 versus '16, and the flexibility that it creates. But when you look at which wells are in backlog, obviously, the wells from '14 aren't going to have as much of the high-intensity fracs. How do you think -- or how would you, right now, plan on which wells in backlog would you complete? Would you focus on the higher-intensity fracs and keep some of the '14 drillings still in backlog? Or how should we think about that?

So the wells that are in backlog, it's a mix. And in that mix, as we go through the year, there is a component of that, that is Red Bank, but it's primarily -- it's really East Red Bank, so it's in Red Bank, the more prolific area. And so we'd feel good about going to that. We'd probably initially take the backlog of wells that are out of Indian Hills and South Cottonwood or the Alger area, do those first and then go to those Red Bank wells.

And firstly, Ron, what you're seeing is that, when we say we're doing 60% high-intensity fracs this year. Of that 40%, part of that is wells that we were doing in 2014, call it a quarter or so of those wells were 2014 wells kind of outside the area that we're going to be focused on -- focusing in on in 2015. So your mix of wells will change a little bit in terms of wells waiting on completion, probably to a little bit heavier weighting of these higher-intensity type fracs. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: Okay. And then on the slide that shows the high-intensity fracs versus -- or the slickwater versus the hybrid, do any of the wells at White at this point include the impact of any of the White sand tests or are those wells represented on that chart still just 100% ceramic?

The wells on the White Unit are all ceramic at this point. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: And if you look at this year's completion program, it sounds like you started to not just combine RCS [ph] and white sand [ph] but even move to 100% white sand [ph]. Based on the early days, do you see yourselves being more biased towards more white sand [ph], and therefore driving those costs down even sooner?

Yes, Ron, we'll continue to do more tests based on what we're seeing. If we continue getting encouraging results, then we'll shift it. We won't go at this point, fully to sand because we want to make sure that the production, to a longer-term, at this point we only have months of production. And so as we get 6 months and a the year, we get more comfortable with making a bigger shift. We sure don't want to impact the -- especially this first part of the well, as you know, you produce about 20% of the reserves in the first year, and we want to make sure with these high-rate wells that we preserve that.

I was going to say that we'll be looking at it, some million dollar savings. And if it's worth it, we'll make bigger a shift. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: And in terms of order of magnitude of those savings, can you give us a snapshot of what your wells are currently costing and to try to get a sense as to where you are from a vendor-level standpoint and where do you think that, that continues to improve even ahead of maybe the move towards more white sand [ph]?

Sure. So thus far, we've seen about a 10% improvement in well costs versus what we are seeing in the fourth quarter. And that we project savings of 15% to 20% as we move further into the year. And when we bake all that in. A good way to think about well cost is $8 million for our base design and $10 million for high-intensity stimulation. So if we do go to all-sand on the slickwater fracs, that could save us an additional $1 million dollars and get us down to $9 million. And all those numbers are prior to the benefits of OWS. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: Okay. And then, Michael, just a clarification on Wild Basin. That's a new infrastructure project for OMS that you're going to start spending this year but really becomes online in '16 and '17, but from a productivity standpoint, is that area supposed -- expected to be pretty similar to Indian Hills in terms of productivity?

Yes, the Wild Basin area productivity is actually -- is obviously, very strong. And what I'd say is it's probably even a little higher than our legacy Indian Hills area. As you can see, especially in the depiction of the White Unit, you can see the hybrid jobs in that area are still above the type curve, both for Bakken and Three Forks. And then as you layer in the slickwater on top of that, they're performing well above the curve. So this is an extremely strong area, which is why we're putting in all this infrastructure to make sure that we can capture that asset. That will be one of the higher-return areas. So the infrastructure project is incredibly important, not only in kind of the timing of that but just getting it in place to measure that we have the infrastructure in place to develop that asset. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: And then lastly, just as you look at the inventory. The inventory went down as you took some of the lower benches away. I think someone asked this earlier, but just to make sure I understood it, a lot of that is really -- was really price-related, is that correct?

Yes. So as you look at the inventory, it's more around the Three Forks. And so the original number, or the number from last year, was reduced by about 400 -- 550 in total. The first 200 wells was really just drilling up the inventory in 2014. So we completed 195 wells last year. And then the last 350 wells is really split into 2 pieces. The first part is around the second bench of the Three Forks, and it's in Cottonwood area. Had a number of tests over there in Cottonwood. And second and third benches; it was really second bench wells, did not look attractive, and so we took those out. And that was about 175 wells in the inventory. And then we also pulled out some Three Forks wells in the first bench that were really in a more distill parts of the position. So North Cottonwood and Foreman Butte were the 2 biggest areas. And we now have the inventory in those 2 areas concentrated in the Bakken. So not really priced-related so much as performance and then just what we drilled last year. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: And then the offset is -- it sounds like a little bit more in the Middle Bakken because of spacing?

Exactly. We -- in general, we've moved the inventory up in the column, so more in the Bakken and in the first bench of the Three Forks.

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

Thanks, Katherine. As a result of all the hard work of our employees over the last several years, we've been able to take what we've learned around the pad development, high-intensity completions and down-spacing and apply and fine-tune those findings in our Indian Hills and South Cottonwood areas as we prepare to accelerate when the environment permits. I'm a firm believer that great companies are made in challenging times, such as these, and I'm confident that Oasis will come out the other side of this a stronger company. Thanks to all of you for joining us on the call today.

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