SM Energy Co (SM) 2017 Q1 法說會逐字稿

Good morning, and welcome to the SM Energy First Quarter 2017 Earnings Conference Call.

(Operator Instructions) Please note, this event is being recorded.

I would now like to turn the conference over to David Copeland, General Counsel.

Please go ahead.

Thank you, Austin.

Good morning to all joining us by telephone and online for SM Energy's -- Company's First Quarter 2017 Earnings Conference Call.

Before we start, I'd like to advise you that we will be making forward-looking statements during this call about our plans, expectations and assumption regarding our future performance.

These statements involve risks that may cause our actual results to differ materially from the results expressed or implied in our forward-looking statements.

For a discussion of these risks, you should refer to the cautionary information on forward-looking statements in our press release from yesterday afternoon, the presentation posted on our website for this call and the Risk Factors section of our Form 10-K that was filed earlier this year.

We will also discuss certain non-GAAP financial measures that we believe are useful in evaluating our performance.

Reconciliation of these measures to the most directly comparable GAAP measures and other information about these non-GAAP metrics are described in our earnings press release from yesterday.

Other company representatives on the call this morning are Jay Ottoson, President and Chief Executive Officer; Wade Pursell, Executive Vice President and Chief Financial Officer; Herb Vogel, Executive Vice President, Operations; and Jennifer Samuels, Senior Director, Investor Relations.

I'll now turn the call over to Jay.

Thanks, David.

Good morning, everyone, and thank you for joining us.

Just to summarize our press release and what we'll be talking about this morning, we're off to a great start for 2017 and on our multiyear growth plan.

Before Wade and Herb give you some details on our quarter results, I just want to highlight 3 major accomplishments that really are highlights for me so far this year.

First, following the closing of our QStar transaction in Howard and Martin Counties on December 20, we ramped our rig count in the Midland Basin up to 7 rigs as of today, all of which are capable of drilling long horizontal wells for us, although one of those rigs is currently engaged in coring operations.

We've also been running 3 frac spreads in the last few weeks.

Now that required us to accomplish a great amount of work in a short time period in planning, permitting, contracting, facility installations and all the other necessary operating activities in order to support that rapid expansion.

That's a big deal to me.

Second, we've made significant improvements in the well productivity we assumed when we made our large Midland Basin acquisitions last year.

Now Herb is going to give you more details on those results in a couple of minutes, and I think they're very impressive.

I just want to focus on one aspect of that, which is lateral length.

In the Martin and Howard County area, our acquisition economics assumed we would average right at 8,400 feet per lateral length during our development.

We're now expecting our average laterals just in 2017 to be over 9,000 feet in length.

Doing that requires a lot of land work, acreage trades, agreements and doing all that while accomplishing all the other details of ramping up our program.

That's again been a major effort and a big success for us.

Third, closing our nonoperated Eagle Ford sale during the quarter was a major milestone.

Maintaining liquidity and the strength of our balance sheet are key priorities for us.

And control of the pace and direction of our capital spending is critical to achieving the levels of capital efficiency that we need to perform differentially.

We believe that our marketing process achieved a very good value for that asset, and the proceeds significantly reduced our net debt and prefunded our spending beyond cash flow during the ramp period of our growth plan.

In short, that was a great deal for us and it was very well executed.

What all 3 of those major accomplishments have in common is outstanding efforts from our SM people, many of whom were relocated or reassigned during our recent portfolio transformation.

Our folks have responded to the new opportunities that they're facing and the challenges we see with enthusiasm and great professionalism.

I'm just very proud of them and very confident about our ability to continue to execute with excellence as we move forward.

With that introduction, I'm going to turn the call over to Wade, so he can run through all the good news about the quarter and our guidance.

Wade?

Thank you, Jay.

Good morning, everyone.

I'm starting on Slide 4. So my summary of our first quarter results is higher production and lower CapEx along with the closing of that non-op Eagle Ford divestiture drove a 22% reduction in net debt.

This morning, I have 3 areas to discuss with you: first, a little more on the first quarter's results; and then second, a look at the balance sheet as of the end of the first quarter; and then thirdly, a quick update with respect to our guidance for the remainder of 2017.

So let's start with the first quarter results on Slide 5.

Production of 12.1 million barrels of oil equivalent was well ahead of our guidance of 11.0 million to 11.4 million.

There are a few reasons for this significant production beat.

First, in the Midland Basin, wells we discussed last quarter continued to outperform and we brought 16 new wells online, resulting in 55% sequential growth in Midland Basin production.

Secondly, in Eagle Ford, we completed a 6-well pad slightly ahead of schedule, and those wells came on stronger than expected.

Plus we completed a few DUCs ahead of schedule.

Herb is going to give you more color on our strong performance in the Eagle Ford later.

And finally, there was also a contribution of 200,000 barrels of oil equivalent from 9 days of non-op Eagle Ford production beyond our end of February assumed close date.

So all in, the quarter reflected strong well performance and shorter times to bring wells on production.

Total capital spend came in at $193 million, 4% below guidance of approximately $200 million.

Part of this was due to a 6-well pad in the Eagle Ford North coming on 8% under budget.

Also, with respect to other wells in general, continued efficiencies drove cost below our AFE levels.

I should also add that while the number of wells completed during the first quarter was well in excess of our expectations, a lot of those wells were completed toward the end of the quarter.

So the production impact for the first quarter was somewhat muted.

In regards to realized prices, we realized $27.55 per BOE pre-hedged.

That's the highest realized price per BOE in 9 quarters.

This is the result of higher commodity prices, and importantly, progress in improving our commodity mix to include larger portions of high-priced Permian Basin black oil.

This puts us on track for improving margins over the next couple of years.

I will also point out that realized pre-hedged NGL prices were up 88% year-over-year and 10% sequentially.

NGLs were 24% at production, and the fundamentals continue to look favorable.

LOE, including ad valorem, generally came in as expected.

Last quarter, we discussed the first half of 2017 having LOE above our average $4 for the year guidance and the second half being below $4.

It's worth noting, for modeling purposes, ad valorem tax is significantly higher per unit in 2017 compared with 2016 due primarily to the sale of Raven/Bear Den, which had nominal ad valorem as well as the effect of higher commodity prices in 2017.

So adding it all up, adjusted EBITDAX was $172.2 million for the quarter, well ahead of consensus.

So clearly a solid quarter.

Now turning to the balance sheet on Slide 6. Certainly, the closing of the $800 million non-op Eagle Ford sale was one of our key objectives for 2017.

Having executed on this, we ended the quarter with 22% reduction in net debt and $1.6 billion in liquidity at the end of the quarter.

We've run a number of sensitivities on lower oil prices and higher cost, and we believe that this sale largely pre-funds are expected 2-year outspend.

We like to remind people that we have no maturities on our senior notes until 2021, and we feel very strong about the strength of our balance sheet.

As already announced, we completed our regularly scheduled redetermination process on the credit facility.

The borrowing base and commitments are $925 million, and that reflects the sale of the non-op Eagle Ford.

The lenders also modified terms to expand allowed hedged volumes.

I'm on Slide 7 now.

The new terms allow us to hedge up to 85% of projected production over the coming 3-year period.

This gives us substantially more leeway compared with the prior terms based on PDP.

As a result, we've already increased our hedged volumes for 2017 through 2019, and you can see the details of those hedges in the slides in the appendix.

Finally, a quick update to our guidance as we turn to Slide 8. We are pleased to report an increase in our full year production guidance by 1.5 million barrels of oil equivalent to an estimated range of 41.5 million to 44.5 million BOE.

Second quarter 2017 production is forecast at 10.3 million to 10.7 million barrels of oil equivalent.

All other line items are left unchanged, including CapEx.

Regarding the divestiture of our Divide County Bakken assets, we had a large number of participants in our sale process and ended up scheduling more data room visits and presentations than we had anticipated, which resulted in us pushing our bid date back a few days.

We still expect to be able to complete this process by midyear.

So as I said in my opening summary, higher production and lower CapEx drove excellent results for the quarter.

Clearly, our successes in optimizing drilling and completion technologies are already showing up in well performance.

And efforts to drive cost efficiencies are showing up in our capital spend.

I'll now turn the call over to Herb who will give you some more color behind these efforts.

Herb?

Thanks, Wade, and good morning, everyone.

As Wade just described, we completed a very successful quarter, delivering on our production and cost targets while at the same time significantly increasing our activity level.

We are putting the pieces in place for our expanded 2018 program, which as we've laid out is expected to deliver significant production growth, margin expansion and increased capital efficiency.

And we're quickly and successfully ramping up our activities.

At the end of the fourth quarter, we were running 4 rigs and 1 frac spread in the Midland Basin and Eagle Ford.

Now only 4 months later, we are running 8 rigs and 4 frac spreads in the same core plays.

And we are getting top-quality contractors.

Also importantly, as I'll show, we are bringing on some outstanding wells in both plays.

Today, I'm going to cover 3 topics.

First, as Wade mentioned, I'll give a little more color behind our production beat in the first quarter.

Second, we'll provide some examples of what we're doing technically to improve our operations in the areas that really matter.

And finally, we'll review some new well results from the quarter, which in short, continue to exceed expectations in both the Midland Basin and the Eagle Ford.

On the production beat, we were really hitting on all cylinders during the first quarter.

Production was above expectations at each of our field locations.

The major contributors were in several categories.

First, more new wells were brought on earlier than planned.

This was a result of more frac stages pumped per day as a result of excellent execution on zipper fracs by our completion crews followed by faster plug drill-out times.

We are now routinely stimulating an average of 6 to 9 stages, and I should add, large stages per day and drilling out as many as 30 to 40 plugs in a day.

That means the time from commencement of frac operations to the start of production from a pad is getting shorter and shorter.

And of course, that means our financial returns are getting better.

Then well performance is exceeding expectations.

As you'll see in a minute, all of the wells we brought on during the quarter exceeded their type curves, some by a very significant margin.

Then well uptime percentages were well above expectations.

For example, in the Southern Eagle Ford, our uptime has improved from around 86% 3 years ago to 99% year-to-date.

High uptime percentages, which is a key metric for us, were achieved out of nearly every field office in the company.

I should add that we measure key performance indicators at each field operation.

So we were able to assess where we're leading and where we're lagging, and we're able to continuously improve our operations in terms of production and costs.

Everyone from field operators to managers in all of our operating areas have a sophisticated dashboard in front of them to know how they are doing in close to real-time.

And that leads the improvements that are flowing to the bottom line in terms of production, revenues and operating costs.

So now I'll turn to Slide 9 and the second topic today, applying technology to optimize the development and drive efficiencies.

Starting with core work.

In RockStar, one of our rigs is currently dedicated to a data acquisition program, as Jay mentioned, involving the coring and logging of 3 vertical wells at key locations across our acreage position.

These are critical to our ability to tying to our 3D seismic data and better map our target horizons.

We expect to collect around 4,400 feet of core from the Middle Spraberry to the Lower Wolfcamp zones of the RockStar and another 1,500 feet of core and open-hole logs at Sweetie Peck.

This data will enable us to assess additional prospective intervals and optimize our landing zones and completion designs.

Consistent with the detailed technical approach we applied previously in optimizing Sweetie Peck and evaluating the RockStar acquisitions, we have proven that securing and integrating this data early in our development program provides significant value by improving capital efficiency, and ultimately, builds our drilling inventory.

So next, let me address completion optimization.

We have 3 completion crews actively completing wells across the Midland Basin right now.

Our standard completion design includes a slickwater fluid system with 167-foot stages and sand loadings of 1,850 to 2,000 pounds per lateral foot.

We zipper frac all of our pad wells.

We're continually seeking to optimize from the space completion design by testing changes in, for example, fluid volumes, sand loading, stage spacing, perforation cluster spacing and configuration and use of surfactants.

We take a very deliberate and logical approach to modifying a minimum number of variables in offsetting wells to better analyze the impact of individual changes.

So here, it's our real objective to optimize our recipe before commencing our expanded 2018 development program that we've talked about.

As an example, if you look on the right side of Slide 9, you'll see the result of changing the completion design in 2 Venkman drilling spacing wells in our RockStar area.

Our predecessor operator completed the first well, while we completed the second well by applying what we learned technically over our years of experience at Sweetie Peck.

From a headline perspective, the lateral lengths, sand loading and stage spacing are all very similar between the 2 wells.

However, we brought in our optimizations, our SM Energy recipe, if you will, like higher slickwater fluid volumes, different mix of sand meshes and surfactant changes.

As you can see, these changes resulted in 60% more cumulative oil production through the first 120 days online.

Clearly, our optimizations worked and will improve return significantly, and we're going to apply them elsewhere.

When we completed our acquisition evaluations last year, these were the types of upside that we had some confidence that we could deliver, and now we are building the track record in the RockStar area.

Now turning to drilling.

In both Sweetie Peck and the RockStar area, we are focused on drilling as many 10,000-foot lateral wells as our leasehold configuration will allow, as Jay mentioned in his opening remarks.

As we've shown in detail previously, longer laterals provide significant incremental net present value or NPV.

Our land teams have been actively trading, and in some cases, acquiring leasehold in order to maximize the opportunity for 10,000-foot drilling.

So far this year, we have added 1,300 acres from these transactions.

We are working this hard and to date have already drilled 20 10,000-foot laterals and have several more in progress.

Adding into this is another way that we optimize value, and that's through the use of pad drilling.

Given the cost efficiencies associated with pad drilling, all of the horizontal rigs that we are running today in the Midland Basin and Eagle Ford are drilling on 3- to 6-well pads.

The use of multi-well pads ultimately leads to lower cost completions and facilities and a smaller footprint for our operations.

We achieve savings through a number of areas, for example, less pad and road construction, use of walking rigs that enable rapid movement from one well to the next and optimization mud systems, less water supply infrastructure, efficient mobilization and high utilization rates of completion spreads, less produced water handling infrastructure, more efficient sizing of facilities and more efficient and fewer hookups to midstream infrastructure.

Clearly, this combination of longer laterals and pad drilling significantly enhances the returns that we are delivering from our development program even at current commodity prices.

You might ask why this is important.

As we've talked about previously, our 2017 program is really focused on laying the foundation for our ramped-up 2018 program and beyond.

We are driving toward efficient pad drilling at density.

Yes, that's pad drilling at density.

We're doing that by focusing on locations where we can readily construct and access well pads, drill to multiple pay horizons, put in place and access water supply infrastructure, install production facilities and connect to midstream offtakers.

This will enable us to deliver a program of scale and efficiency at drilling, completing and connecting our wells quickly, efficiently and safety.

Contiguous acreage is a big part of that.

This is all part and parcel of our 3-year execution plan.

So the final optimization area that I will touch on today is our implementation of what is now widely being called the digital oilfield.

Simply put, this really involves online systems that pull data in from all our fields' data systems and our financial systems to yield real-time feedback on how individual wells are performing.

We get a read on everything from production through revenues and allocated costs.

As I just mentioned, in the Eagle Ford, we are really pleased how this has progressively improved our well uptime percentages across the field over the past 3 years, specifically in the southern area from 86% to 99% year-to-date.

We receive constant data feeds from each of our well heads that enable us to immediately respond to any downtime or to optimize artificial lift if it makes sense to do so.

It allows our field people to be focused on the most leveraging activity that they can perform on any given day.

This is the sort of blocking and tackling that you expect to see from a top-tier operator.

And I've got to say that personally, with over 32 years’ experience in the business, I just continue to be amazed at how our teams keep on coming up with new technologies and creative new ways to get even more efficient in producing our wells, developing our acreage and optimizing well results.

Now before turning to well results, let me preface discussion of RockStar area wells with the map on Slide 10, which shows the recent ramp-up of industry activity in and near the area from January to April this year.

28 rigs are currently running in this area that we show on the map, of which 5 are ours.

And as you can see on the slide, this is quite an uptick from the start of the year.

In just 3 months, the industry rig count in this area has increased by nearly 60% from 18 to 28 rigs, which is an acknowledgment of the excellent returns, the Tier 1 returns or top-tier returns that many operators are achieving from the wells completed in this area.

Turning now to well results at RockStar that are shown in Slide 11.

I think here we can say that the results really just speak for themselves.

So far, all the wells that we have completed as SM Energy in the RockStar area exceed the 1 million barrel equivalent peer type curve, and all wells exceed our acquisition model expectations by a significant margin, especially when factoring the risk weighting that we apply for valuation purposes.

Slide 12 shows detail in our 3 newest completions in addition to 8 wells we highlighted last quarter.

These Guitar North wells target the Lower Spraberry, the Wolfcamp A and the Wolfcamp B. They were all nearly 10,000-foot lateral wells completed with our base completion design.

They have not yet reached their peak 30-day IPs.

So we have provided 20-day IPs, although I need to point out that the peak 20-day IP is still increasing at Lower Spraberry well here.

Again, these are just outstanding wells.

All 3 are exceeding preacquisition unrisked expectations of peak single day IPs of 850 to 950 BOE per day, and as you can see, by quite a margin.

We should see some stellar returns from these wells.

One last point, I should note that these wells were previously named Korean Elizabeth wells and were renamed the Guitar North wells.

Now turning to Eagle Ford.

We've talked before how the prolific gas rates and rich NGL yields from our Eagle Ford program are able to deliver strong Tier 1 returns.

That's over 50% IRR at $0.65 per NGL a gallon and $3 per million BTU gas.

As we previously talked about, we've invested in numerous pilots, tested completion designs and well spacing, reviewed the results and have now mapped out our view of the optimal development under current commodity prices.

So here I'm pleased to point to Slide 13, which shows the continued outperformance of 6 wells in our Eastern type curve area.

These wells started producing in the fourth quarter of 2016 and continue to significantly outperform our type curves from 900-foot spaced wells, even though these new wells are spaced in a staggered 625-foot configuration between the Upper and Lower Eagle Ford or just 312 feet apart in plan view.

We showed early performance on these wells last quarter.

And as you can see now with another 3 months of production, the production outperformance continues, having produced over 30 BOE per lateral foot in less than their first 6 months on production and exceeding our type curves from the wider spaced wells.

During the first quarter, we also completed several wells in our Eagle Ford North area with significantly enhanced completions.

We are really pleased with the initial production from these wells and can see them potentially right there with the East area in being capable of generating returns that are well above our investment thresholds.

While we have focused our CapEx program on our Midland Basin opportunities, we do want to be clear that our Eagle Ford returns are also very competitive at current commodity prices.

And we have the capacity to ramp up here.

While we are talking about the Eagle Ford, one more item I'd like to update is regarding the shut-ins we have in the East area as an offset operator works through a [mow the lawn] drilling and completion development program across our lease line.

We have been in constant communication with that operator and have been progressively shutting in wells a couple of weeks in advance of their program and several weeks afterwards.

They commenced this program in December and initially had planned around 30 wells.

We now understand they've upsized the program to around 36 wells, so we are anticipating continued drilling shut-ins through August.

Their expanded program is considered in our increased full year guidance, and it's reflected in our 2Q production forecast.

Importantly, so far, all the wells of ours since restoring the production have been working their way back to their initial decline curves, with no apparent permanent degradation in productivity.

So with that, let me just summarize.

We are executing well.

We're successfully ramping up activity in the Midland Basin, and we are delivering top-tier returns from our wells.

We are going to keep executing to the 3-year plan that we shared with you in February and report back to you on our progress quarterly.

I'm very confident in the ability of our team, our employees and contractors to deliver on that plan.

With that, let me turn the call back over to Jay.

Jay?

Well, thank you, Herb.

In closing, today, I just want to note that the priorities of the company going forward are unchanged.

Our 2017 priorities and plan focus on helping us optimize our development plans in order to maximize the value of our assets.

We believe that the quality growth we are going to generate during our multiyear plan period in both cash flow and economic drilling inventory should result in differential performance for our shareholders.

With that, we'll be happy to take your questions.

(Operator Instructions) Our first question comes from Jeb Bachmann with Scotia Howard Weil.

Jay, maybe Herb, on this one for Howard County, you guys talked about doing the optimization work as well as the core log data.

Just trying to figure out when you think you might have that data from those programs in house where you can actually implement them in your next well designs.

Yes, Jeb, this is Herb.

First of all, we have quite a bit of core data, and we've got a lot of log data already.

So what the additional core data is really for certain areas so that we can see additional prospective horizons, their core data where we don't have them and also to home in on landing zones with some specific details.

So I'd say it can be an optimization beyond our optimizations from here, but we want this really to drive up our inventory.

And I guess, just looking at Slide 9, you talked about the improved completion designs.

Just wondering, Herb, you guys have any kind of recompletion opportunities that you could put that to work on at this point?

Or is that something down the road that might be of use?

Jeb, that'd be really down the road.

What -- there's not that many horizontal wells out in Howard County.

And so recompletions isn't really going to be the -- a big driver.

It's really the new wells that we're putting out there.

And I guess, just last one from me.

Could you guys just remind us the percent of your Permian production that's on pipe versus being trucked at this point?

I think it's probably 2/3 is piped, and the rest would be trucked.

And you guys know when it will all be in on pipe?

Do you have any idea on that?

No, I don't really have a number for that.

That's going to basically be rolling, right, because as we're expanding the number of pads, they're trucked, and then ultimately, you get a hook up.

So no, I can't really give a number on that.

The next question is from Welles Fitzpatrick with Johnson Rice.

On the -- specifically on the Eagle Ford Northern test, have you guys seen a difference between Upper Eagle Ford and the Lower Eagle Ford on those results?

And as far as how they're doing versus the curve, would you describe it as relatively similar to what you've seen on the East with those uplifts?

Okay.

Welles, this is Herb.

The -- first of all, there's 6 wells in that area.

And when we looked at them all together, the combined -- and we did different things in some of the wells, they -- overall, they exceeded our investment threshold by quite a margin.

We ran different completion designs in the Upper and the Lower, just simply because the rock properties are different.

So I would say what we're seeing right now, and we believe there's some more optimization room yet, that all of them exceed our inventory thresholds and our -- the -- we've got the Lower Eagle Ford optimized more than the Upper Eagle Ford at this point.

So we'll see -- continue them, but it's all making our hurdles with the way we've designed the completions with these 625-foot space stacked wells.

Okay, that's great.

And then on the cost savings on that, should we think of that 8% as taking the 5.2 down to 4.8?

Or was that more cost savings on sort of some of the science that one would expect you had drawn on a test like this?

It was really about efficient execution, some things where we increased the cost and some things where we dropped the cost overall.

But it was really basically no hiccups in execution.

It was probably the biggest part of it, and that led to the 8% reduction.

Okay, perfect.

And then just one last one, more of a conceptual question.

It seems like the Eagle Ford is pretty much punching pound for pound with what guys have in the Permian now.

If you guys were to accelerate, if you were to add rigs beyond what's planned, do you think that, that might be a little bit more weighted towards the Eagle Ford?

Or are you kind of happy with the CapEx split you have now?

This is Javan.

I think if we have -- and we have some interesting flexibility, I think, based on how things are performing with our capital program as we go forward.

I think we're going about as fast in the Permian as a prudent operator would go at this point, given the data we need to collect.

So if you had another dollar you want to spend in CapEx -- and obviously, Wade would probably say if we had another dollar to spend, we'll lower our debt level.

But I think the Eagle Ford is a great option.

The economics are very strong.

It would be a very easy add for us.

And as we go through the year here, if it looks to us like it makes sense from a cash flow and cash balance standpoint to go do that, I think the Eagle Ford makes a lot of sense and may very well be the first place you would put another dollar.

Our next question is from Michael Hall with Heikkinen.

I just wanted to, I guess, go back to the completion cadence in the quarter relative to expectations.

It was a bit higher than I think what you guys had indicated last quarter.

I guess, how do we think about that cadence playing out through the rest of the year?

Initially, basically pull those out of the 4 quarters, or is there potential that given you're kind of moving through completions in a faster order than expectations that maybe we'll actually see a higher completion count as we make our way through the year?

Yes, this is Herb.

It's -- really we're sticking to our plan basically.

We've got flexibility now on how we do things.

But because we've been so much more efficient in executing, we're able to get things done faster, but we're still sticking to our plan.

We haven't changed CapEx guidance at all.

So that's really where we are.

Okay.

So would there be, I guess -- in that context then, like would you potentially drop some activity, drop a crew or something in the back end of the year?

How do you kind of balance that out in your current thinking?

Well, so right now, we're just executing the plan, and we've laid out what we're going to do in the second quarter.

And then we'll be looking at how to optimize at the end of the year.

But at this point, we're seeing no reason to change our number of completions or to revise our CapEx view.

Okay.

Fair enough.

And then can you comment on what maybe -- maybe you didn't, I missed this.

But what the average lateral length was in the Permian program in the first quarter?

Okay, I don't have it just for the first quarter, because that -- I figure out that -- we've been focusing on the 10,000-foot laterals, and they're nominally that way, 9,700, 10,000.

So there's some -- there's one pad where we did 6 7,500-foot laterals, and that's simply, because the lease geometry set that up.

So I don't have an average, but it would be high 8,000s, I'm guessing, for the quarter.

Okay, that's helpful.

And then in the Permian, what's the kind of current run rate on a full drill completing equip cost in Howard relative to Sweetie Peck, and what are those running?

Yes, I think we have that laid out in our last quarter presentation and in the appendix on this one.

So you can see what those costs are right there in the back.

Those numbers include some of the plays -- our expected cost for this year.

So there's a little bit of inflation actually in those numbers.

On Slide 19.

On Slide 19.

And then last one, just in the Eagle Ford, I think there were 17 completions.

Were those all in that 1Q '17 completions area that was highlighted?

I guess, it's slide 13.

Wasn't really sure.

All 17 in that area?

No, those -- that's 6 of them are where that 1Q '17 completions are.

There were quite a few over in the East area also.

That came on basically in mid-March, so late in the quarter.

Our next question is from Paul Grigel with Macquarie.

Herb, on the uptime percentage, an interesting point there.

What do you guys view as the repeatability of that moving forward, driven by the technology?

And what do you have modeled into the assumptions of guidance as you look out for the rest of the year in that regard?

Okay.

So on the uptime percentages, we've seen progressive improvement everywhere, and that's really just systems-based.

And it's sustainable when we're basically in an area -- like if you have an offset operator fracking away with well, that drops our uptime.

So it's very programmable.

You can plan out pretty well what's going to happen for -- where operations are affected by other operators or you own operations.

So I would say, sustainability is there from the system standpoint.

What you have to plan out and what you put into your guidance is really what you know in your program is going to be affected.

So I'd say we plan that out and it's quite detailed.

So it's really hard to put an umbrella statement on that.

Okay.

No, that's understandable.

It's good color.

And then maybe one for Wade.

With the change in the credit agreement and the ability to up-hedging as a percent of projected production -- obviously in the near term, you guys have ample hedging.

How should we view the longer-term strategy moving forward and the willingness to implement that at a greater extent?

Yes, Paul, what we had added some hedges, as I said, and you can see that.

I think what you should expect is we'll be very focused on kind of the more near term, the next couple of years, especially during the periods where our leverage is the highest.

So it's -- it'll just be a quarter-to-quarter thing where we look at the volumes and how comfortable we are.

I can't say much more than that.

I wouldn't anticipate us adding a significant amount of hedges if you look out to the third, fourth and fifth year from any point in time.

Our next question is from Bryan Levy with Key Group Holdings.

On Slide 13 of your presentation, you show Eagle Ford on a 2-stream basis.

What would these wells look like on a 3-stream basis, and can you quantify what sort of uplift we could see from that?

Yes.

Bryan, I appreciate the question.

I don't think we'll tackle that one here on the call because I'm not good at doing math in my head like that.

So if you wouldn't mind following up with Jennifer following the call, I'd appreciate that.

And we don't give [URs] you ours on wells like this.

These are terrific was.

They're performing really well.

You can see the cums over 150 days.

It's a great set of wells.

Our next question is from Anthony Diaz with Raymond James.

First off, I was just looking to see if you could give us an update on the Viper well.

I know we're flowing back in February.

We're kind of expecting in maybe next couple of months from then to get some kind of indication, and I'll let you guys answer that first, I guess.

Well, Anthony, I'm not sure where you got the information we're flowing back in February.

We recently completed the well and we just started flowback.

We don't have any data to share with you yet, because it's just way too early.

Again, I'm not sure where that February thing came from.

Okay.

My apologies then.

Yes, and then from there, that Martin County block you guys have that's just right across the border, what kind of data do you guys have, and could we expect any drilling on that in 2017?

I know you have challenges across there.

I have some great results with [Silver City]well, et cetera.

Yes, this is Herb.

So we'll be getting to that late in the year, putting a rig up there.

I don't know whether we've got completions that will be done up there this year, but it may be close.

Okay, all right.

That's fair.

And then just my last question.

That 1,300 acres, could you just remind us where are you focusing those swaps and those trades?

And then kind of going forward, where are you guys looking specifically?

So there's really 2 things on those swaps.

One is to get to the longer laterals where we can configure the acres to get 10,000-foot laterals fit in there.

And then the other is to increase our working interest in those wells.

So that's where we can get some trade.

So we'll trade out of what we call isolated acreage that's kind of out there in different places -- trade out to the logical operator in exchange for an operator who has working interest in acreage in our DSUs.

So it's a very logical, and we got sophisticated operators out there, and everyone's trying to do the same thing.

It makes good business sense.

(Operator Instructions) Our next question is from Biju Perincheril with Susquehanna.

In your January presentation, you showed a couple of slides with (inaudible) boundaries for Lower Spraberry and Wolfcamp B. And first, I was wondering if there is any update to those maps.

And second, your plans for drilling at Wolfcamp B over Lower Spraberry wells on that Southeast portion of our acreage in Howard County?

Yes, Biju, this is Herb.

So first of all, no, we haven't issued any updates to those maps.

However, as you're aware with that activity level, there's quite a bit of industry activity.

And if you're watching the Railroad Commission reports, you'll see that there is periodically new wells out there.

And those in some cases, we'll be expanding what we deem as the kind of confirmed areas within our sweet spot.

And in particular, you may notice there's one well, the Thumper well, which was just reported to Railroad Commission, I believe, yesterday, which looks to have moved the Wolfcamp A confirmed contour based on the IP given for that well quite a bit east.

We're going to keep monitoring those.

And at logical point, I imagine, we'll update those maps, but we haven't updated them so far.

And when do you plan to test either the Wolfcamp B or the Lower Spraberry on the eastern side of your acreage?

So that's -- it's in our plans for late this year.

So I don't know whether we'll get production in this year, but we would at least have a rig on it.

Our next question is from Chris Stevens with KeyBanc.

Just a quick follow-up on the Viper well question.

Did you only complete one well on that area?

Or are you going to have multiple wells passing a couple different zones that you're completing at the same time?

Yes, we -- this is Herb.

We just completed the one well.

And as Jay mentioned, we're just -- we just started flowback on it now.

I'll just note that Thumper well that Herb mentioned is only 4 miles -- 4, 5 miles to our west.

So I mean, clearly, we've got a great looking -- good-looking Wolfcamp B section out there and Wolfcamp B. we're cautiously optimistic here.

We just don't have any data yet to share on the Viper.

So...

Got it.

And then just in terms of the optimization of your development plans in Howard County, I guess, you guys want to test the optimal sort of spacing.

So is there any color you guys can provide on what sort of downspacing test you guys are going to do this year?

Yes, I think you'll see that we've got -- so far, we've got quite a few where we've done tests stacked, Lower Spraberry, Wolfcamp A, Wolfcamp B. And you'll see, as we proceed through the program this year, we'll be doing a different stagger configurations, which tighten the spacing but in a staggered manner where we've got thick pay.

So you'll be seeing those results coming out as we go through the year.

Our next question is from Mike Scialla with Stifel.

I apologize if you addressed any of this.

I missed the first part of the call, but was interested in the -- asking about the core data that you've collected both in Sweetie Peck and Howard County.

Wondering if you could compare and contrast maybe the 2 areas.

And I think you've done, at this point, some downspacing tests in Sweetie Peck.

Wondering based on that data that you've seen, is any of that applicable to Howard County as well?

Okay.

Mike, there's quite a few things you put in there.

So first, the core data we just acquiring the core now, the new core.

We have considerable core from -- actually from the predecessor operator, Rock and QStar.

So we've got that data.

We've got correlations with the logs.

That's well in hand.

Now we're getting core through the full section.

So we're able to look at more prospectivity, and that's ultimately going to build inventory, we hope.

So that's -- the ones I just mentioned, the 4,400 feet RockStar and the 1,500 feet at Sweetie Peck, we don't have that core yet, except for -- from one well at Rockstar we just finished.

The spacing at Sweetie Peck, yes, certainly, everything we've learned at Sweetie Peck, the completion design recipes, we've been applying that at RockStar.

And it's been great for us.

We do have staggering of wells at Sweetie Peck, and that's informing us for the RockStar program.

So it's part of our Sweetie Peck results have integrated tighter spacing in a staggered manner.

And we've really learned quite a bit on how to optimize from the past couple of years' performance from Sweetie Peck.

Is it fair to say at this point, you're comfortable with the spacing that you are using at Sweetie Peck?

And if so, can you remind me what -- where you settled there?

Yes, that depends on the individual horizon and how thick it is.

So you have to look at how much oil in place is in an interval, and that drives how tight your spacing is.

So it's one of the things we went over in that January call, kind of those fundamental things that really matter.

So it's driven by the oil in place, how tight.

And it's really the volume that we attribute to a well that drives what the spacing is.

So it isn't so much, oh, it's just the spacing.

It's -- you start from 8 wells per section and then you tighten it as there's more volume in place.

And if I remember correctly, were you at 12 wells in part of Sweetie Peck in the Wolfcamp A?

Yes, you can -- in parts of -- that would be Lower Spraberry, you can do 12 and more potentially in the Lower Spraberry.

And in the Wolfcamp B, you can do 10 or more in some cases.

And in Wolfcamp A, we haven't done anything other than 8.

I think -- this is Jay.

I think one of the interesting differences between the western side of the basin and the eastern, I think here is where your frac barriers are.

And, Herb, I guess, my impression, just to make sure right on this, is that in Howard County area, you're probably -- A, B is probably kind of codeveloped as opposed to Sweetie Peck where we're really kind of codeveloping the Lower Spraberry and the A together.

And I think as you to get to the eastern side of the basin A, B is more of, I'll call, it a tank.

And the Lower -- and the Sprayberry is sort of a tank as opposed to the west side where there is really not a lot of frac barrier between the Lower Spraberry and the A. So there are some differences, and we're learning a lot.

We have reservoir models that we used to be able to make forward projections on these things based on the results we see.

And I think those will be really helpful to us in Howard County as well.

At this time, I am showing no further questions.

I would like to turn the call back to Jay Ottoson for any closing remarks.

Well, thanks again for calling today, and we look forward to talking with you next quarter.

Thanks.

The conference is now concluded.

Thank you for attending today's presentation.

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