Chord Energy Corp (CHRD) 2015 Q1 法說會逐字稿

Good morning. My name is Ed, and I'll be the conference operator for today. At this time, I'd like to welcome everyone to the first-quarter 2015 earnings release and operations update for Oasis Petroleum.

(Operator Instructions)

Please note that this event is being recorded. At this time I would like to turn the call over to Michael Lou, Oasis Petroleum's CFO, to begin the conference. Thank you, Mr. Lou. You may begin your conference.

Thank you, Ed. Good morning, everyone, this is Michael Lou.

Today we're reporting our first-quarter 2015 financial and operating 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 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 of adjusted EBITDA to the applicable GAAP measures can be found in our earnings release, and on our website. We will also reference our May investor presentation, which you can find on our website.

With that, I'll turn the call over to Tommy.

Good morning, and thank you for joining us today. Oasis delivered a great quarter, with production over 50,000 BOEs per day, exceeding the top end of our guidance range by 3%. Additionally, CapEx was right in line with our budget.

The team was able to drive down LOE per BOE by 11% quarter-over-quarter, and reduce overall costs through both service cost reductions and increased efficiency. We'll dive into more detail on these items momentarily, but I first would like to step back and review our plans and our inventory strength.

First, we're on track with our capital plan this year, completing 23 gross operated wells during the quarter. While we spent 38% of our CapEx in the first quarter, this was expected due to running 16 rigs at the end of 2014, and dropping to five rigs by the end of February; running six frac crews at the end of 2014, and dropping to two by the end of January; and completing 23 gross operated wells or 19.2 net during the quarter, which was both on plan and represented about 29% of our planned completions for the year. As expected cash flow outspend is measured by EBITDA less interest, and CapEx was right around $100 million, and cash flows should be close to being balanced for the remainder of the year.

Second, production from wells that we completed during the quarter generally outperformed our expectations, which drove production above the high end of our guidance range. About 30% of the wells were completed in the core, and the remainder were completed outside the core. 13 in Red Bank, two in Montana, and one in North Cottonwood. We completed 60% of the wells with high intensity completion techniques, which continue to prove to be a great economic opportunity, as Taylor will discuss.

Third, this week we're dropping down to four operated rigs, as we drilled a little faster than we originally planned. We continue to expect to hit our 2015 plan for spuds and completions with this change.

Lastly, we're focused on prudently managing capital in this oil price environment, and we've been encouraged by the recent positive moves in prices. We have the flexibility to accelerate activity if prices continue to move up, especially given our 91-well backlog at the quarter end, and our extensive inventory in the heart of the Williston Basin. As we've discussed previously, substantially all of the activity for the remainder of 2015 will be focused in Indian Hills and South Cottonwood, or in the core of the basin.

To help better define the core, we're breaking out South Cottonwood into two areas now. The first area, which was included in the core DSU count of 72, is now going to be reported to as Alger, and the remaining acreage will be referred to as South Cottonwood. Alger includes 18 operated DSUs, and 17,000 net acres.

The total core acreage, including both Indian Hills is comprised of 74,000 net acres, 825 locations, 701 of which are located in the Middle Bakken or the first bench of the Three Forks. At the current pace of completions, this equates to 8 to 10 years of inventory. Outside of the core, our extended core and fairway regions, we have another 2,221 locations we can drill, over 80% of which is economic at a $60 WTI price.

We rolled out this inventory detail at year end based on extensive use of geologic and reservoir modeling. And our confidence in this inventory continues to increase, especially as we see longer dated well results, purchase further geologic studies, and match production history to our models.

At our latest investor presentation, which was updated this morning, you can see the detail around our three operating regions and our assumptions. I'm going to turn the call over to Taylor to discussing operations in more detail.

Thanks, Tommy. I'd like to keep people's attention on our investor presentation that we posted this morning. We mentioned in our press release last night, some of the recent performance of our high intensity completions in both Indian Hills and Alger.

On slide 12 of the presentation, we show the well results of the White unit and the Helling Trust unit, compared against historical wells in Indian Hills and Alger, respectively. The first thing that I would point out is that the average performance in these areas for the Middle Bakken base completion wells range from about 675 MBOE to 750 MBOE, which is right in line with what we've been highlighting all along. Additionally, the Three Forks first bench wells are performing around 575 MBOE and 600 MBOE, which again is consistent with our historical disclosures on type curves. What really jumps off the page is the performance of the high intensity completions, which based on early time performance, are more than two times the corresponding type curves.

On the next slide, we highlight the economics of these wells, which show even at $60 WTI pricing we're delivering wells ranging from 22% to 42% IRRs, with high intensity completion techniques. This is using current well costs of $9 million for the high intensity completion wells. We have driven high intensity well costs down in the core while continuing to use 100% ceramic and about 220,000 barrels of water and slickwater jobs, and about 9 million pounds of sand in our high-volume proppant jobs.

Our team has done a great job of continuing to become more efficient at the new high intensity completion styles. As we have previously discussed, they have continued to move the aggregate costs down, as well as the relative costs versus our base jobs. We've been able to move these costs down significantly due to lowering of our service cost, efficiencies in the completion process, and better infrastructure and logistics.

High intensity completion wells have cost $10.6 million in late 2014, and that we projected to cost $9.5 million in 2015, are now getting closer to $9 million. We will continue to look for ways to drive down costs without sacrificing well performance and economic profitability.

On our last call we discussed the 100% sand slickwater tests that were underway outside of the core. The first such test was in Montana on the Jimbo Federal. We saved about $600,000 on proppant costs, and early days would indicate that the well performance is in line with the nearby ceramic slickwater tests in Montana, which is over 30% above the nearby wells after 90 days of production.

The early time performance is riding the 575 MBOE type curve compared to historical wells in Montana, that are more in line with the 450 MBOE type curve. Obviously these results are encouraging, as we think about the value impact this can have on our Montana acres position.

We have the ability to continue to modify the proppant mix in our completions, but we'll approach the changes in a judicious fashion, based on extensive testing over the last two years, especially in the core. We're excited about the rate of change that we are driving in the Williston Basin and we continue to expect to complete 60% of our wells with high intensity completion techniques. Additionally, we continue to expect service costs to come down during the remainder of the year by about 10%.

I'll now turn the call over to Michael.

Thanks, Taylor. Our team at Oasis has done an incredible job so far managing through the past six months of lower commodity prices, and the uncertainties and challenges that it has presented. We exceeded our production guidance range in the first quarter due to strong operations and extremely strong well performance from our recent high intensity completions, while staying on budget, on capital, and on the numbers of wells completed.

Given this performance, we have set our second-quarter guidance range at 47,000 BOEs to 49,000 BOEs per day, and we have raised the lower end of the annual guidance range, which is now 46,000 BOEs to 49,000 BOEs per day, or up to 7% growth year-over-year. As Taylor discussed, we've been able to reduce capital costs faster than expected. Although it's too early to adjust our budget for the year, if we maintain capital and operating cost reductions, it's safe to assume we will either come in under budget, or have increased activity.

Importantly, we continue to drive improvements to our profitability and cash margins. Our differentials in the first quarter improved to $7.85 per barrel, down from $9.74 per barrel in the fourth quarter of 2014. The second quarter should continue to improve, and is currently trending in the $7 range.

We made significant improvements to LOE this quarter, which came in at $8.62 per BOE. This was our lowest quarter since our acquisitions in late 2013, and over $1.50 per BOE better than our 2014 average. We are clearly seeing increased benefits from our infrastructure, as well as better run time performance across our base wells.

We are lowering our annual LOE guidance range to $9 to $10 per BOE. Additionally, OMS delivered record performance with $10.7 million of EBITDA in the quarter, or $43 million annualized.

Production taxes trended down slightly from the fourth quarter. We are pleased that North Dakota has passed a proposal to lower aggregate oil production taxes from 11.5% to 10%, starting in 2016. This continues to strengthen our ability to maintain strong operations during uncertain times.

On that note, we have taken additional steps to continue to strengthen our balance sheet and our financial flexibility. In early March we executed a $463 million equity offering, which helped us repay borrowings on our credit facility, and lower aggregate debt levels. We also announced in early April that we amended our credit facility to increase the term to five years, as well as increase our committed level to $1.525 billion. This gives us $1.4 billion in liquidity.

Importantly, we continue to have a strong hedge portfolio, with over 60% of our production hedged through the remainder of 2015 at over $83 per barrel. Based on our current budget, which was planned at $50 WTI, our spending for the remainder of the year is expected to be within cash flow, so we plan to maintain solid liquidity. Given our strong cost control and improving commodity prices, we could potentially do even better than that. Additionally, our financial position and our significant core inventory provides us the ability to accelerate our pace when we're ready.

Overall, we had a tremendous quarter. We beat production expectations, continued to have success in high intensity completions, drove down capital and operating costs, improved differentials, and improved our financial flexibility. Given our long inventory of drilling in the core, we are well positioned to deliver strong results, maintain our growth in 2015, and potentially increase that trajectory into the future.

With that, I'll turn it over to Ed for Q&A.

(Operator Instructions)

Our first question comes from Scott Hanold of RBC Capital. Please go ahead.

That's a pretty good update, and you probably can't see it, but the market certainly is taking notice. When you look at these higher-intensity completions that are outperforming by 2 times, they seem to be sustaining that level for an extended period of time. What do you think is going to happen with these wells, and when do you feel comfortable to make a more bold EUR update?

Scott, we talked a bit about this in the last call. We'd really like to see at least a year or more of extended data, but it's production data and then it's also pressure data that we're gathering from pressure observation wells, along with the recoveries that we expect to see. One of the significant things that we want to make sure about is the impact of these big completions, as we do them in spacing. You've seen us do a number of tests, where we're fracking all the wells and spacing them with high-intensity completions, so that's the interplay. But I would say a year plus to get a better feel.

Okay. So you need that much. Okay, that's fine. And then, as you look at the well performance, and the economics are improving obviously in your portfolio with lower costs and better performance, crude prices ticked up here recently.

As you look at making a decision as to whether you spend or save, any service cost reductions and efficiencies, how does the balance sheet play into that? Do you have a preference of getting debt to EBITDA down first, prior to stepping on the accelerator, or if the returns are there, you would be willing to increase sooner?

The great thing is, Scott, is that we've got very strong economics here. Our IRRs are improving. We're driving down both capital costs and operating costs, and we've got a really strong inventory, long inventory in the core, where we're getting those returns.

So you're making good money at $60. Especially as oil prices have come back, the back part of the curve is above that level. We feel like we've got really strong economics.

The balance sheet is always going to be an important piece of that equation, as you mentioned, and so it will be a balance of whether or not you pay down debt or continue to accelerate a little bit, with a little additional activity in the back half. With higher pricing then, what our budget was, which was at a $50 oil price with additional cost savings, that certainly is going to give us some optionality in the back half, that we can make those decisions. We haven't made that yet, on what we'll do, but we have some flexibility. Both of them are good news, right?

Absolutely. Maybe I could have shortened my question by just saying is there a target debt to EBITDA at this point in time in the cycle you'd like to stay within, as you look over the next year or two?

I still think that longer term, at a longer-term oil price, we've always said a 2-times debt to EBITDA over time is our goal. But that is at a more balanced longer-term oil price. We'll just have to see where oil prices level out over time, as opposed to reacting to shorter-term swings on that oil price.

Thank you.

Our next question comes from Neal Dingmann of SunTrust. Please go ahead.

Just a quick question on the OMS, on the administrative services. It seems like you continued to ramp up that business up, even in a tough market. I'm just wondering what you think the opportunity is? Obviously you've done adding more of the gathering lines, I forget what the total is there, and just the wells in general. Could you talk a little bit more on what you see on the upside there in the near term?

Neal, on OMS, we continue to have really strong performance there. Obviously as we're moving into the core, we move into where we have very strong infrastructure. We had a record quarter and the guys have done a great job of getting more and more of our water on our disposal system.

So, record quarter from an EBITDA standpoint at $10.7 million, and we hope to continue that performance. We are still moving forward with our project of additional infrastructure in that Wild Basin area, that's still on schedule. It should be online mid-2016, and that's where you'll see additional drilling from us in Wild Basin, towards the end of this year, coming on-line middle of next year.

So we're all on-plan for all of that, that infrastructure is obviously in the very core of the Bakken, and so we think it's very well-positioned, where we have a lot of drilling inventory there. So it's needed infrastructure in a great area, and we think it makes a lot of sense from a return standpoint of putting that infrastructure in. Highly critical for us, as well as good economics on putting that infrastructure in.

I would agree, and just one quick last follow-up. Just on differentials, you actually did quite well for the quarter. Maybe for Mike, your thoughts going forward on modeling? Do you think it will stay about where it was in the first quarter? I think you had mentioned $7.85 or $8, somewhere in there. Is that a pretty good going rate?

I think it's actually improving in the second quarter, it's closer to that $7 range. So down a bit further, which is great news. The other thing you'll notice is on the gas side, our differential came back in a little bit.

We think that, through the course of the year, that can improve as well. Obviously, with NGL pricing and the Henry Hub price coming down, our realized price came down a good bit. But we think that actually can continue to improve through the rest of the year, as well.

Great. Thanks for details.

Our next question comes from David Tameron of Wells Fargo. Please go ahead.

When I think of your completion backlog of, is it 91, whatever that number is, when you originally did your plan, what were the expectations for that backlog? Was it the growth throughout the year to drop down throughout the year? Can you just talk a little bit more about that, and if anything -- I think I know the answer to the second part, but if anything has changed?

When we came into the year, it was 72, and our expectation going out of the year as we did our budget, I think was just under 70 or so. Basically the same.

Everything else being equal, we'd expect a slight draw down from here?

I'm sorry? Yes, it should be a draw down, Dave. That's expected, as we had a higher rig count the beginning part of the year. We knew the wells on completion or those ducks would grow a bit in the first half the year, and then it would come back down to where we're more basically flat by the end of the year.

Mike, I think you talked a little bit about the tax changes, but can you dummy it down, can you quantify what exactly you expect to see in your financials, as a result of the tax law changes?

Well, it's relatively straightforward, Dave, in that all North Dakota production on the oil side would go from 11.5% down to 10%, until oil goes above $90. And then it would go back to 11.5%. But if it stays under $90, that's the general way to think about it.

We'll start seeing that effective?

Effective in 2016.

And just one big picture. Congrats on the high-intensity completion results so far. But one big-picture question, I guess for Tommy, I'll call you a seasoned veteran, having been through a few cycles.

How do you think this ultimately plays out as far as maybe your view on oil prices, not necessarily Oasis, but your view on where you think oil prices end up? Can you just give us some big-picture thoughts?

Dave, what we've said historically is we budget around the $80 to $85 oil price, which is what we think is a long-term normalized price. Last year, we actually budgeted a bit higher than that, I think $90, relative to I think the average for last year was like $94. But I think we'll be a slow grow out of here, but $80 is probably, from a long-term basis what we'll continue to plan around, and we have for the last five or seven years.

Any thoughts on service contracts and doing anything -- jumping off a little bit to a different question, but if those are your thoughts at $80, I imagine you could lock up some contracts today with the expectation we're not going back to $80. How should we think about what's your plan on your philosophy around service contracts, and locking in longer term?

We'll probably stay pretty flexible here over the near term, and just see how things play out. We don't have any plans to start locking things in at this point.

Okay. I appreciate the color. Congrats on a good quarter.

Our next question comes from Michael Hall of Heikkinen Energy Advisors. Please go ahead.

I guess the question on my end around -- just as I think about 2016, if we hold the current macro and cost environments flattish, in line with the strip let's say, should we expect to think about the 2016 program to mirror the 2015 program from the perspective of focusing on the core and similar levels of high-intensity completions?

I think it will be basically the same. We won't need as much activity to offset decline because we're getting -- that base decline will start to shallow out. But it will still be -- I think that the way to think about it going forward is, is that we'll start to, as we move forward here, expand outside of the core, but we really, outside of the White Unit and the Hagen Banks, that Wild Basin part of Indian Hills is effectively undrilled, and so we'll transition over to drilling in there next year.

We've gone slow because it's infrastructure poor, which is one of the reasons why we're focused on that. Then we'll start to expand outside of those two primary areas, keeping in mind that we don't want to run too fast in any one area and overload infrastructure. We saw that last year in Indian Hills.

But from a high-level capital efficiency standpoint, it doesn't sound like too big of a change, I guess, 2015 versus 2016? Meaning the program mix shouldn't be materially different?

It will be pretty much the same.

Marginally better a little bit because of the first quarter, as you can tell, and as Tommy mentioned, only 30% of the wells were in the core in the first quarter, so that was a bit of a carryover from 2014. So our inventory or those wells waiting on completion that we talked about previously, that 72, those wells waiting on completion actually have a better mix going in the end of 2015 versus where they were the end of 2014, so you're actually marginally probably a little bit better, if anything.

Remember, while we've got $565 million in DNC this year, relatively flat to up on volumes, as we go into next year, that requirement, going back to what I said earlier on the shallower decline, that requirement is more like $375 million to $400 million.

Great. A nice tailwind. I guess on that point of declines, do you roughly have a number of what PDP declines look this year and how that looks next year?

It's about -- it's about 35% this year, going down to somewhere between 25% to 30% next year.

That's helpful. And I guess on the other question I had was around it sounded like pretty good encouraging data from the sand and slickwater job in Montana. What's the thought process or timing around taking that and testing sand loading relative to ceramic in the core?

Michael, we started in Montana, and then we actually moved that into Red Bank. It just brought some wells on there that have sand and sand and resin-coated sand. The next step would be to go one deeper, which would be likely Indian Hills area, and it will be first test, probably have a portion of ceramic in and some sand, and we'll see what the impact is and leg into it that way.

Is that a second-half test?

Yes. That will be second half.

And then last of mine, LOE guide was actually a little higher than the first-quarter result. I was just wondering if there was anything non-recurring in the first-quarter number that we ought to be aware of?

There's nothing in there that's non-recurring, but we want to be able to see and make sure that we can continue to hit that across quarters, before we guide down too far. It's a big jump from where we were last year. The guys have done a great job on that, but we want to continue to see that.

All right. That's all I have. Good execution, thanks.

Our next question comes from Don Crist of Johnson Rice. Please go ahead.

Good morning. One for Taylor, on the White Unit and Helling Trust, you previously talked about 30% to 50% uplifts in IRRs leading to 10% to 30% uplift in EURs -- I'm sorry, in production leading to 10% to 30% uplift in EURs. With the wells tracking 2 times their respective type curves, do you think that there's more possibility for uplift in EURs there?

So your question, I do think there's the potential for upside in the EURs, and we're encouraged. We modeled the wells from a production standpoint. Currently our model at 30% uplift, and so, if they continue to outperform at that level, that gives us some upside which is good.

And then from a reserve standpoint, it's just longer data time. It's probably as much around how do these wells interact in spacing, and what is the right spacing with the type of uplift we're getting. And so we just need more time to digest all that and get to a final answer.

But do you think the delta there could be 2 times what you thought before, or do you think it's more of early time acceleration on those wells versus ultimate EUR, given what they're doing today?

It could be higher. Is it 2 times? I don't know. The great news is that it is performing at 2 times, and we're excited about that, and optimistic. As we get further out, we'll make adjustments.

And turning to OMS, is there any update on the potential sale given the new IRS proposed regulation on qualified income?

Good question, Don. We're still in the process, we're still looking at a number of different options. Obviously we've seen that as well, but there's no real update at this point, other than we're continuing to work through options. The good thing is we've got a lot of options, a lot of good options, and so we'll continue down that path.

One final one for me. On OMS, assuming that you get it sold at some point, what would be a fair multiple to put on that current EBITDA run rate?

Don, that's a hard one. Obviously as we're working through this, we're looking at a number of different things. To me, the midstream asset is very similar to midstream assets in oil and gas; and in fact, OMS will have those type of assets in Wild Basin as well.

If you look at where midstream companies trade, they trade significantly higher than where E&P companies trade, in a 10 to 14 times EBITDA multiple. Where is it fair? I don't know. We think our assets are in that same vein. It's critical for the production, and the production in the core of a great region.

So we feel like there's good supply there. It's infrastructure that will be used for a long time in the future. Good stable cash flows in that business going forward.

That's all I've got. Everything else has been asked. Thanks.

Our next question comes from Tim Rezvan of Sterne, Agee. Please go ahead.

I was hoping to follow on a little bit to the last question. Your stated build out for the Wild Basin project is really a three-year project. Given the prolific wells that you announced here, what are you thinking about, in terms of maybe pulling the timeline of that forward? Is that contingent on some type of monetization? How do you think about that timeline, given the wells?

Tim, on the timeline of the infrastructure in Wild Basin, while there is capital that we have allocated to be spent over three years, it's important to note that infrastructure will be on-line and ready in the middle part of 2016. There will be continued build out of that system over time, but that is more in line with our current view of drilling in that area. And so some of that capital can obviously be brought forward, if needed. But right now, it doesn't need to be built out significantly ahead of time of where you're going to be drilling.

So you're going to be drilling that asset for a long time. There's a deep inventory, as we mentioned, 10 years of inventory in the core. And so the infrastructure can be built out over the course of time. We're just trying to give you the full scope of what that infrastructure might look like over that whole period to get to that asset.

So given what you've seen, we can probably expect a pretty healthy capital allocation there next year?

Yes. I think what we've said in that area is it's probably -- infrastructure is probably close to $100 million in that area for next year.

Just a follow-up. I was hoping to again beat on the LOE topic a little more. There was discussion on better run-time performance, driving LOE down.

But then I also noticed you mentioned only 30% of the completions were in the core, in the first quarter, if I caught that correctly. I imagine completions will migrate more into the core, where you have infrastructure in the rest of 2015. Do you see that as a potential additional tailwind to LOE moving forward?

Yes. We have more of our wells in areas that we have good infrastructure, and given where we're drilling this year, it is going to be in areas that we have good infrastructure. That is certainly a positive for LOE. Our guys have done a great job of continuing to drive down costs, and keeping that base production up, as well as keeping the cost down on that base production. So that's that run-time performance is better.

As well as our drilling program this year is going to be more in areas that we have better infrastructure, so that should be beneficial as well. So we feel good about LOE and that's why we lowered our LOE guidance range.

I appreciate the color. Thanks.

Our next question comes from James Sullivan of Alembic Global Advisors. Please go ahead.

Thanks for taking the questions. I wonder if you could give a rough distribution of your -- when you talk about the 90 waiting on completion wells, a rough distribution of those wells across your geographies? And if you don't want to give it by Indian Hills versus Alger versus Red Bank or whatever, maybe you could characterize where they are in terms of your core, extended core and then fairway, the distinction you gave on your presentation?

Of that total, there's about 25 that would be outside of the core and those are -- the majority of those are in the Red Bank area, but there's also some in Montana, and a handful in North Cottonwood. The rest of the count is in the core.

Great. So to follow-up on that, obviously, so some of that is remaindered work from 2014, the stuff that's outside the course I assume obviously, and you guys have guided to this, that you're working to stay or concentrate activity in the core area there.

Can you just speak to, to what extent you are impeded in the process of concentrating that way, by insufficient infrastructure? Obviously, you are in Wild Basin and that's why you are investing in that. But just looking at Alger or Indian Hills, how far ahead do you need to continue to run in terms of extending the SWD stuff, and gathering, and so on?

Really for the plan that we have this year, the infrastructure is, or will be in place by the time we complete the wells in each of those areas. Like Michael talked about, we're really building out some additional infrastructure in new SWD wells, in a few of those areas, but we'll be in good shape by the time we get that work done on the new wells.

Just to clarify, is it right to assume that the front-load infrastructure cost is what's causing the higher rate of CapEx spend vis-a-vis the well completion schedule on a percentage basis this year?

The capital in the first quarter and why it was front loaded was, as Tommy mentioned in his prepared remarks, it's all that capital activity that was happening at the end of 2014 going from 16 rigs down to 5, going from six frac crews down to two. Our pace last year was around 45 well completions a quarter.

We did move that down to 23, but 23 is still nearly 30% of the activity this year. So some of that was known slowdown of our program, but that was what really front-loaded the activity for the first quarter versus the next three quarters. Infrastructure is always a part of that, but I wouldn't say infrastructure was the biggest driver of that front loading.

I was just looking at the numbers and I think that you spent about -- if you're looking at the $705 million budget number, you spent close to 40% of that to complete maybe 30% of your expected wells. Obviously, that delta can move around quarter to quarter, but I just thought maybe it had to do with running in front of yourselves for preparing pads and so forth, or preparing for completions.

But just to move on to one other question, if I can squeeze one in here, you did mention in your script about being cash flow neutral for the rest of 2015. I just wanted to clarify if you meant that you thought next quarter you are going to be free cash neutral, or that you would hit free cash neutrality by Q4? Or whether you meant the average of the three quarters would be, or the aggregate of the three quarters would be free neutral recall?

I think it's really each of the next three quarters will be cash flow neutral. I think we're there in the second quarter.

Okay, great. Thanks.

Our next question comes from Dave Kristler of Simmons & Company. Please go ahead.

Good morning and great work. Looking at the production beat a little bit, can you break down, from a percentage basis, what portion of that would be maybe ascribed to better weather than previously anticipated or budgeted for, versus just better well performance?

I think that it's -- milder weather is always helpful. But I think it's really driven by well performance. Obviously, there's some benefit of weather, but I think it's largely driven by well performance.

Okay. I appreciate that. Thinking about the high-intensity completions that you have been doing, is that also combined maybe with better landing of laterals, or is there anything else that's influencing it, or is that just truly apples to apples?

David, I think it's -- relative to the base wells, the horizontals were really drilling the laterals in the same manner at this point, and so we attribute it really to the completion.

I appreciate that. Just as a follow-up to that, given the uplift you're seeing in the economics from that high-intensity completion, can you expand that out of the core, or will you even consider testing it outside of the core a little bit more, to see if maybe you can pull more of non-core into core, assuming the same price environment?

That's a good point. We actually did the style completions, and you can see it in the presentation, I don't know the page off the top of my head, but we have tested it in Red Bank, Montana, and it's on page 11. And so we've got it in a number of areas outside the core, and one of the things we're doing, as we're going through this -- the commodity price downturn, is really tearing apart all that work we did in those other areas, to get an understanding of where we could go back to, with lower cost.

The lower costs are huge, if we can do those completions and get the uplifts we've seen outside the core, and get costs down like we talked about with the Montana well. And that Montana well is 575 MBoe, the cost is around $8.4 million, and we'll continue to work to get that down. But with that cost and that well performance that we're seeing so far, the economics are -- it's economic at $60, and boy, at $70, it's looking pretty darn good.

Really appreciate the added color, and again, great work on the quarter.

Our next question comes from Gail Nicholson of KLR Group. Please go ahead.

Just a couple of quick questions. The $9 million well cost, does that include the OWS savings?

Yes.

Great. And then hedges for 2016, it looks like you had put some on in the $64.98, $65 range. Is that $65 that magic number where you see that you want to add to that hedge position?

I don't know exactly what the magic is, but the way we modeled it for next year is -- this year we modeled it $50, next year we modeled it $60 to accomplish all the things that we've talked about in terms of activity and cash flow neutrality. So our view is, to the extent we can do things that are $5 or $10 above that is accretive to our plan, and if we can be accretive to our plan and protect our downside, then we'll continue to do that.

But I think it's going to be -- the way we look at it internally is we layer things in, on small chunks, ones and twos, and watch where the market goes. One and twos as in thousands of barrels a day.

Just one last one. The White Unit that you did, testing that tighter spacing, as you continue to see that strong performance, is there any thought that you could maybe go tighter in spacing, based upon the White Unit performance? I guess any additional clarity would be great.

We're actually going to test, as we go into Wild Basin next year, we're going to test a number of different spacing configurations, and some will be a little tighter than what we did in the White Unit. So we'll be doing that, and testing it, and over time, we'll come up with what the right spacing is.

Okay, great, thank you.

Our next question comes from Jon Wolff of Jefferies. Please go ahead.

Nice results on the higher-energy fracs. I was curious, on the LOE, if there was some benefit -- I understand a lot of it probably was tying in systems related to the energy deal, but I was wondering if there was any energy benefit on artificial lift, is the first question. In terms of lower commodity prices helping LOE?

So with respect to the artificial lift, not a lot of impact related to lower energy costs. We are seeing reductions in some of the other cost elements, so equipment, chemical programs, certainly fuel for vehicles and things like that, but that's not as huge a part of that LOE cost.

If you think about it, and you guys can correct my percentages, but I think we were running something like 45% through our systems to our disposal wells, and now that number is somewhere in the high-50%s, on a percentage of water volume.

We went from 40% to 48% from the fourth quarter to the first quarter.

And that's meaningful. Trucking water is not very cost effective. That's why infrastructure -- what you're seeing now is why infrastructure is so important.

So these are natural synergies that would have happened, at least in some way, if oil prices had stayed at $100 or $90?

Yes, just the more we can get going through our systems to our disposal wells, the better.

And second one is, I don't disagree on the $80 long-term outlook, but Bakken wells, I think we can agree that they have relatively short duration. And how does that -- does it really matter what your long-term view is on oil or how does that color your thinking? It makes you think your company is more valuable probably, but does it color your thinking on trying to secure more acreage, on trying to prepare for the day where oil is higher? How do you think about that?

I think you always -- like I say, we have always run the business around that price, so we -- to look to that for -- whether it's $80 is just a nice round number, but somewhere $80 to $90. And we're always looking to build on our positions, build on the big blocks.

Scale matters on a macro sense, scale matters on a micro sense, especially when you start talking about infrastructure. So I think we're always looking to build around where we are with the longer-term view of what we think the price is, somewhere in that $80 to $90 range.

I guess what I'm getting at is how does it affect the budgeting in a year like this or next year? You're obviously taking capital down. You can't plan for $80 oil this year, I guess is what I'm saying.

No. No. Basically, you start thinking about it, this year is -- especially as we start to layer on more hedges in the second half, it's sad. We've got to be mindful of the balance sheet.

And so for instance, next year, as we've talked about we're planning around, from an activity standpoint, planning around a $60 price deck for next year. Where we have the opportunities we talked about with hedges, to be accretive to that, if that's our base case, then everything we can do above that through hedging to lock that in, the better.

Your base case and your long-term outlook are two different things from a near-term standpoint?

Yes, because we're looking at the market all the time.

Okay. Last one is, there's been rail accidents, two or three every four or five months. The Department of Transportation has some new rules coming out around May 12.

I don't know that will -- I was curious how you think about how the cost structure for rail might change, number one, and then secondly, any momentum on pipelines, just as sort of a guaranteed safety and safe and maybe even more economic way out?

The good thing is that there are a lot of pipelines going in, in the basin. So overall, both avenues, both rail and pipe, are extremely important to us. But there are a number of new projects that are continuing to come into the basin.

There's a few larger projects that will be coming in at the end of 2016, that actually could get, depending on what happens with Bakken production, could get it to where you could pipe all the volumes out of the basin, which is a fantastic place to be. We continue to have very strong rail partners as well, and obviously take safety as a major concern.

The pricing on rail has been relatively strong, given that Brent and TI have gapped out a little bit. It's helped our differentials. Don't know exactly where the regulations will shake out.

Will there be some additional costs? Maybe some. I don't think it's going to be incrementally material, but there will be some potential additional costs on the rail side. But they're very strong partners right now for us, and we think it can still be very economic for them going forward.

Would your position be that you're maybe not to be in the position of an anchor shipper, but are willing to take down some contractor volumes in a scenario where there's an open season, something like that? I know it's early.

We've taken the position that we can help with committed levels for the right pipeline systems coming in. And we'll do that, to help encourage people to come into the basin as a whole. The good thing is we've had a lot of people come in, and so obviously we can't commit to every single project, but the basin is a big basin, and overall, producers have been very supportive of those transactions.

Got it. Very helpful. Thank you.

Our next question comes from John Nelson of Goldman Sachs. Please go ahead.

I want to circle back to your comments about the potential to under spend full year CapEx guidance. I'm just curious, are there logistical or operational constraints that would hinder you from increasing the mix of high-intensity completions, just because it seems to me maybe to be one of the more attractive uses of discretionary capital, would be to increase the mix of those completions, given it wouldn't necessarily dictate an increase in long-term commitments.

I'm not sure if there's investments in getting enough water to do slickwater completion, things along those lines. Could you just help me think about why you wouldn't necessarily increase that mix?

Sure. So we've got 40% is what we expect to do that are non-high intensity. We're going to do 60% of the high-intensity version. We could increase that. We've -- in the plan, the way we're approaching it is doing almost all of the Bakken wells will be high-intensity completions.

And then we have split, as you go into the Three Forks, look at it, at this point, as being 50/50 high-intensity and base jobs, and that's the place that if we continue to see great performance, we could bump up the number of high-intensity completions we do in the Three Forks. The reason, at this point, we're still doing half is, again around spacing and understanding drainage, and how these wells interact with these completions and spacing.

That's helpful. And then, just to Tommy's answer a moment ago about potentially planning the 2016 budget at $60 a barrel, when you think about that, is that planning within cash flow at $60 per barrel, or just depending on where you want to take the balance sheet in 2016? It's the baseline, or the base-case commodity assumption is $60 a barrel?

That basically is staying balanced with DNC, as we have talked about. If you go through all the mathematical gymnastics, it's going to be 550 to 570. You take off the interest, you end up at 400 and you're basically covering your DNC program.

The spread would be the other stuff, that's the non-DNC CapEx, which obviously a big chunk of that is Wild Basin. Which is one of the reasons why we're working that whole side of the business, is to try to manage the non-DNC capital for 2016 at $60.

John, clearly we don't have a capital budget for 2016 that's formal. We're just trying to give you a feel for, if you are in lower oil prices for longer, that's a level that you could spend at, and keep production flat, and live within cash flow.

And we've always said below a $60 or below-type level, that's what we'd do. So we're trying to give you a view of what 2016 could look like, and a spend within cash flow type scenario.

That's very helpful. That's all for me. Congrats on the quarter. Thanks.

Our next question comes from Noel Parks of Ladenburg Thalmann. Please go ahead.

Just a couple questions. Sorry you touched on these. I hopped on a little late.

I was curious, I've heard from some other operators that they've actually increased working interest in some wells because of non-consents from partners. I know your working interest is pretty high across your acreage. I just wondered if you'd seen any of that?

We have seen a little bit of an increase, but it's not dramatic. It depends on the areas. Like you said, we have a pretty high working interest, and with all the activity in the core, it's not, at this point, a huge number, but we continue to monitor that.

Okay, great. On the service section, more specifically the materials cost side, what have the trends been like with the pricing of ceramic versus white sand, as we've gone through the oil price downturn?

So we've seen a little bigger move in the price of ceramic early, and probably no surprise. When you get in a commodity price correction like this on the front end, one of the easy things or levers that you can pull is to eliminate ceramic and go to white sand, and a number of operators did that.

So, a little more pressure on ceramic early. Sand has moved. It hasn't moved as much on a percentage basis, but we would expect that probably both sand, and importantly, resin, as you move through the year, probably have more room to go.

Just wondering, have you done much or learned much from any microseismic surveys you've done over the past few quarters?

We haven't done any microseismic surveys recently, within the past year. We did a number of them earlier in the play, and so that's 2012, 2011, 2012, and I think a little bit of 2013 had microseismic data.

And it was very helpful in understanding spacing between stages for our fracs, and also frac heights, and what the right level of intensity is for the frac. But we haven't done any more since then.

Is that anything you think would give value at this point, or is that all pretty much established, the information you got from it?

We don't have plans to do any more at this point. We feel like we've got some really valuable data, but that we're in good shape.

That's all for me. Thanks.

Our next question comes from Jason Smith of Bank of America, Merrill Lynch. Please go ahead.

Congrats again on the strong results. Just to come back to OMS and the potential monetization again. Tommy, I think when you were asked earlier, you said you had a number of different options. Can you maybe just elaborate on that, in terms of what the options are that you're looking at?

Jason, this is Michael. We're looking at -- and what we've talked about in the past is whether or not it's a strategic partner or a financial partner coming in to fund some of the, call it the capital that we have over the next two years, and owning an interest. You can also do it through -- called a private-type vehicle, where there's just a straight financial partner, or it could be a public entity, like an MLP or other.

So there's a whole host of different options. The key for us is obviously, we'd like to retain operations here. We think having those operations are incredibly important. Obviously, we want to get the highest valuation as well, and make sure that we're getting the right value out of these assets. They're highly valuable assets, so just making sure that we get the right value out of it, when we get in with a partner.

So there's a lot of growth here. It's in the core of the basin, so it's an extremely strong position to be in from that side. We're looking at a lot of different alternatives there.

But a big key is going to be the right partner, and as we've talked about, execution is extremely important, and timeliness. We don't want to be drilling wells where we can't move the products or the water. There's a component of it that's financing. There's a component of it that's having the right partner.

Understood. Thanks. Just to be clear, is there an active process going on right now?

To look at alternatives, yes.

Okay, thanks. And just given the comments that's been in the presentation all year round, around monetization, is there anything beyond OMS that you're looking at as a potential candidate at this point?

Not really.

That's all for me. Thanks, and congrats again.

Our next question comes from Andrew Coleman of Raymond James. Please go ahead.

Thanks for taking my questions here. Just had a quick one here on the gas side of things, clearly gas is a small piece of the revenue stream here, and definitely recognize gas prices have come down.

What's your view in terms of how basis would improve itself and realizations improve themselves going through the year? And is that something OMS can participate in, or is that more of a function of the reduced flaring requirements, and the shortage of facilities up in the basin on the gas handling side?

Good question, Andrew. We're in very good shape on the flaring side. We've been well above the regulations, so we're doing a very good job, and that's important for us, obviously, to be a very good community partner, as well as, it's helpful for us to get as much sold as possible.

For us, the realized price has come down, largely because of where Henry Hub is, as well as the NGL price coming down. We do think that can improve through the rest of the year. We have traded historically significantly above Henry Hub, and that has come down here a little bit in the first quarter, but we do think that can expand again, based on what we're seeing towards the end of the year. I don't have a specific premium to call at Hub but it should get a little bit better from here.

I think that's fine. I guess lastly, what's the rough BTU content of the gas that you're seeing or selling up there right now? Is it still 1,500?

On average, it's in that area. There are certain parts of the basin that get a little bit richer, but in general, 1,500 is a good number.

Thank you.

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

Thanks, Ed. We have had a tremendous quarter. We beat on production expectations, realized exceptional results in high-intensity completions. We continue to drive down costs, both capital and operating costs, and we've improved our financial flexibility.

We have a tremendous drilling inventory, not only in the core, but across our entire position in the Middle Bakken fairway, and we're well positioned to maintain our growth in 2015 and potentially increase that trajectory as we go forward. Thanks for joining us today.

Thank you for joining us. The conference is now concluded. You may now disconnect.