SM Energy Company (SM) Q1 2017 Earnings Report, Transcript and Summary

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 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 assumptions 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 about 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 of Operations; and Jennifer Samuels, Senior Director of Investor Relations. I'll 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've been talking about this morning, we are off to a great start for 2017 and on our multi-year growth plan. Before Wade and Herb give you some details on our quarter results, I just want to highlight three major accomplishments that really are highlights for me so far this year. First, following the closing of our QStar transaction in Howard and Martin County's on December 20, we ramped our rate account in the Midland Basin up to seven rigs as of today, all of which are capable of drilling long horizontal wells for us, although one of those rig is currently engaged in coring operations. We've also been running three fracs spreads in the last few weeks. That required us to accomplish a great amount of work in a short time period in planning, permitting, contracting, facility installations and all of 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 wealth productivity we assume 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 are very impressive. I just want to focus on one aspect to that which is Lateral Length. In the Martin and Howard County area, our acquisition economics assume we would average right at 8400 feet for Lateral Length during our development. We are now expecting our average lateral just in 2017 to go over 9000 peak in Length. Doing that requires a lot of land work acreage trades, agreements and doing that all while accomplishing all the other details of ramping up our program, that’s again been our major effort and a big success for us. Third, closing our non-operating Eagle Ford sales 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 outset and the proceeds significantly reduced our net debt and pre-funded 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 three of those major accomplishments have in common is outstanding effort from our SM people, many of whom who are relocated or reassigned during our recent portfolio transformation. Our folks have responded to the new opportunities that they are 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 non-op Eagle Ford divestiture grow with 22% reduction in net debt. This morning, I have three areas to discuss with you. The 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 to 11.4. There are a few reasons for this significant reduction beat; first, in the Midland Basin. Wells, we discussed last quarter, continue to outperform and we've got 16 new wells online resulting in 55% sequential growth in Midland Basin production. Secondly, in Eagle Ford we completed a six-well pad slightly ahead of schedule and those wells came on stronger than expected. Plus we completed a few docks 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 while we end the quarter reflected strong well performance in 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 the six well pad in the Eagle Ford north coming on 8% under budget. Also with respect to other wells in general, continue 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 towards the end of the quarter. So the production impact for the first quarter was somewhat needed. In regards to realized prices, we realized $27.55 per BOE pre-hedge. That’s the highest realized price for BOE in nine 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’ll also point out that realized pre-hedge NGL prices were up 88% year-over-year and 10% sequentially. NGLs were 24% of production and the fundamentals continue to look favorable. LOE including ad valorem generally came in as expected. Last quarter we discussed in the first half of 2017 having LOE above our average $4 for the year’s guidance and the second half being below $4. So it's worth noting for modeling purposes, that 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 effective higher commodity prices in 2017. So adding in all up, adjusted EBITDA 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 prefunds our expected two year outstand. We’d 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. It's already announced we completed our regulatory schedule redetermination process on a credit facility. The borrowing base and commitments are $925 million and that reflects the sale of the non-op Eagle Ford. The winter has also modified terms to expand allowed hedge volumes. I'm on Slide 7 now. The new term 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 hedge volumes for 2017 through 2019 and you can see the details of those hedges in the slides and 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 to 44.5 million BOE. Second quarter 2017 production is forecasted 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 now sale processed 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 mid-year. So as I said in my opening summary, higher production and lower CapEx growth, excellent results for the quarter. Clearly our success is in optimizing drilling and completion technologies that 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 Herbert who will give you some more color behind these efforts.

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 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 efficiencies. And we're quickly and successfully ramping up our activities. At the end of the fourth quarter, we are running four rigs and one frac spreads in the Midland Basin and Eagle Ford. Now, only four months later, we’re running eight rigs and four frac spreads in the same four place and we’re getting top quality contractors. Also importantly as of show, we are bringing out some outstanding wells in both place. Today I’m going to cover three topics. First, as Wade mentioned, I’ll give a little more color behind our production days 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 will review some new real results from the quarter which in short continue to exceed expectations in both the Midland Basin and the Eagle Ford. On the production days, we were really hitting on all corners during the first quarter. Production was above expectation at each of our field locations. The major contributors were in several categories. First, more new wells were brought on earlier than planned. This is 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 drilled out times. We are now routinely stimulating an average of 6 to 9 stages and that 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 start of production from a pad is getting shorter and shorter and of course, that means our financial returns are getting better. The well performance is exceeding expectations. As you’ll see in a minute, all of the wells we brought on during the quarter exceeded their tight curves some by a very significant margin. And well uptime percentages were well above expectations. For example, in the Southern Eagle Ford, our up time has improved from around 86% three years ago to 99% year-to-date. High uptime percentages which is a key metric for us were achieved out of nearly every field ops in the company. I should add that we measured key performance indicators at each field operation. So we are able to assess where we are leading and we are lagging and we are able to continue to improve our operation in terms of production and cost. 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 developments 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 three vertical wells at key locations across our acreage positions. These are critical to our ability to time our 3D seismic data and better map our target to horizon. We expect to collect around 4,400 feet core from the Middle Spraberry up to the lower Wolfcamp zones at the RockStar and another 1,500 feet of core and open the logs at 3D path. This data will enable us to assess the traditional perspective intervals and optimize our landing zone and completion designs. Consistent with the detail 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 provide significant value and proven capital efficiency and ultimately builds our drilling inventory. So next let me address completion optimization we have three completion crews actively completing wells across the Midland Basin right now. Our standard completion design include a slickwater fluid system which 167 foot stages and sand loading of 1,850 to 2,000 pounds per lateral foot. We zip or frac all of our pad wells. We are continually seeking to optimize from the space completion design by testing changes in for example fluid volumes, sand loading, space basing preparation cost of spacing and configuration and use of [indiscernible]. We take a very deliberate and logical approach to modifying a minimum numbers of variables and offsetting wells to better analyze the impact of individual changes. So here it’s real objectives to optimize our recipe before commencing our expanded 2018 development program that we talked about. As an example if you look on the right Slide 9 you’ll see the result of changing the completion design and two banking drilling spacing at wells in our RockStar area. Our predecessor operators completed the first well while we completed the second well by applying what we learnt technically over our years of experience 3D tech. From a headline perspective the lateral lengths, sand loading and stage spacing are all very similar between the two wells. However we brought in our optimizations our SM Energy recipe if you will like higher slickwater fluid volumes and different mix of sand measures and subtracting changes. As you can see these changes result in 60% more cumulative oil production through the first 120 days online clearly our optimization worked and we’ll improve return significantly and we’re going to apply them elsewhere. When we completed our acquisition evaluation last year these were the types of upside that we had some confidence that we can deliver and now we are building the track record in RockStar area. Now turning to drilling in both Sweetie Peck and 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 significantly incremental net present value or NPV our land schemes have been actively trading and in some cases acquiring leasehold in order to maximize the opportunity for 10,000 per drilling. So far this year we 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 the horizontal rigs that we running today in Midland Basin and Eagle Ford are drilling on three to six well pads. The use of multi-well pads ultimately leads to a lower cost completions and facilities and a smaller footprint for our operations we achieve savings through a number area for example left pad and road construction use of rocking rig that enable rapid movement from one well to the next and optimization of mud systems, less water supply, infrastructure efficient mobilization and high utilization rates of completion spreads, less produced water handling infrastructure more efficient filing of facilities and more efficient and pure spread to midstream infrastructure. Clearly this combination of longer lateral and pad drilling significantly enhances the returns that we are delivering from our development program even at current commodity prices. And you might ask why it’s important. As we’ve talked about previously our 2017 program really focused on laying the foundation for our ramped up 2018 program and beyond we are driving towards efficient pad drilling at density. We assess pad drilling at density we’re doing that by focusing on locations where we can readily construct and access well pads, drill and multiple pay horizon put in place and access water supply infrastructure in oil production facilities and connect to midstream off takers. This will enable us to deliver a program of scale and efficiency at drilling completing and connecting our wells quickly, efficient and safety. Continuous acreage is a big part of that this is all part and parcel of our three year execution plan. So on optimization area that I’ll touch on today is our implementation of what is now wildly been called the digital oil field simply put this really involved our mind systems that pulled 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 really pleased how this is progressively improved our well up time percentages as off the field over the past three years specifically in the Southern area from 86% to 99% year-to-date. We received constant data feeds from each of our wellheads that enable us to immediately respond to any downtime or to optimize our official list 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 a sort of blocking, tacking that you expect to see from the top tier operator and I got to say that personally with over 32 years experience in the business I just continue to be amazed that how our team keep on coming with new technologies and creative new ways to get even more efficient in producing our wells developing our acreage and optimizing water. Now the well let preference discussion of RockStar areas well with a map on Slide 10 which shows the recent land 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 in the map of which five are ours and as you can see on the slide this is quite an uptick from the start of the year. In just three months the industry recap in this area has increased by nearly 60% from 18 to 28 rigs which is acknowledgement of the excellent returns the Tier 1 returns or top Tier returns that many operators are achieving from the well completed in this area. Turning now to well results at RockStar that shown in Slide 11 I think here we can say that results really just speak for themselves so all the wells that we have completed at SM Energy in RockStar area exceed the 1 million barrel equivalent pure type curve and all wells exceed our acquisition model expectation by a significant margin especially when factoring the risk rating that we applied for valuation purposes. Slide 12 shows the detail on three newest completion in addition to eight wells we highlighted last quarter. These entire 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 basic completion design they have not yet reached the peak 30 IP so we have provided 20 day IP but 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 three are exceeding pre acquisition unrisked expectations of single day IPs of 850 to 950 Boe per day and as you can see by a quite margin. We should see some stellar returns from these wells. At that point I should note that these wells are previously named Corrine Elizabeth wells and were renamed Guitar North wells. Now turning to Eagle Ford we talked before how the prolific gas rate and rich NGL yields from Eagle Ford program are able to deliver strong Tier 1 returns that’s over 50% IRR 65% per gallon and $3 per million BT of gas. As we previously talked about we invested in numerous pilot tested completion design and well facing reviewed the results and have now mapped our view of the optimal development under current body fractions. But here I am pleased to point to Slide 13 which shows to continued outperformance of six wells in our Eastern type area these wells started producing the fourth quarter of 2016 and continue to significantly outperform type curves from 900 even though these wells are staged in a 625 configuration between the upper and lower Eagle Ford or just 312 feet of deals we showed early performance on these well last quarter and as we can see now with another three months of production the production out performance continues. Having produced over 30 Boe per lateral foot in less than the first six months on production and exceeding our type curve from the widest base wells during the first quarter we also completed seven wells 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 and being capable of generating returns that are well above our investment threshold. While we are focused on our CapEx program and our Midland Basin opportunities, we do want to be clear that are 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 shutting we have in the east area as an offset operator work through a mobile long drilling and completion development program across our leased line. We have been in constant communication with that operator and have been progressively shutting in wells a couple of weeks in advance of that program and several weeks afterwards. They commence this program in December and initially had planned around 30 wells. We now understand the upside for program to around 36 wells. So we are anticipating continued rolling shutting through August. Their expanded program is considered in our increased full year guidance and is reflected in our 2Q production forecast. Importantly, so far all the wells of our store to production have been working their back to their initial decline carriers with no current permanent degradation in productivity. So with that, let me just summarize. We are executing well, we are successfully ramping up activity in Midland basins and we are delivering top-tier returns from our wells. We are going to keep executing to the three year plan that we shared with you in February, and report back to you on our progress quarterly. I’m 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?

Thank you, Herb. In closing today, I just wanted to note that the priorities of the company going forward aren’t changed. 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’re going to generate during our multi-year plan period involve 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. Please go ahead.

Good morning everyone. Jay or maybe Herb on this one for Howard County. You guys talked about doing the optimization work as well. It's a quarter log data. Just kind of trying to figure out when you think you might have that data from those programs and how we can actually implement in your next world designs?

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 perspective for horizon core data where we don’t have them. And also to comment on landing zones with some specific details. So I'd say it’s going to 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, talk about the improved completion designs just wondering would 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?

That really be down the road. There is not that many horizontal wells out there in Howard County and so recompletions isn’t really going to be the big driver, it’s really the new wells that we are putting out there.

And I guess just last one for 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 by two-third.

And the rest would be trapped.

And you guys know when it will be on pipe? Have 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 are trapped and then ultimately you get a hook up. So, no, I can’t really give you a number on that.

Great, appreciate the color.

The next question is from Welles Fitzpatrick from Johnson Rice. Please go ahead.

Hi, good morning. Specifically on 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?

Well, this is Herb. First of all, there is six wells in that area. And when we looked at them all together combined, and we did different things in some of the wells, overall they exceeded our investment threshold by quite a margin. We ran different completion designs in the upper and the lower because the rock properties are different. So I’d say what we’re seeing right now and we believe there is some more optimization room yet, that all room exceed our inventory threshold and we got the lower Eagle Ford optimized more than the upper Eagle Ford at this point. So we’ll see continued room but it’s all making our hurdles with the way we’ve designed the completion with the 625 foot space of that well.

Okay, that’s great. And then on the cost savings on that, should we think of that 8% as taking to 5.2 down to 4.8? Or was that more cost savings on sort of some other signs that one would expect you to run on a test like this?

Yes, it was really about efficient execution. Some things where we increased the cost, some things where we dropped the cost overall but it was really basically no pick up in execution. It was by the biggest part of it. And that led to the 8% reduction.

Okay, perfect. And then just one last one more of a contextual question. It seems like the Eagle Ford is in a pretty much bunch and bound with what you 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 you’re kind of happy with the CapEx that you have now?

Well, this is Jay. 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 will go at this point given the data we needed collect. So at the end of another dollar you want to spend in CapEx, and obviously, as Wade would probably say, if we have another dollar spend, we will 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 ad for us. And as we go through the year here, if it looks to us like it make sense from a cash flow and cash balance standpoint, I think the Eagle Ford makes a lot of sense. And maybe it will be the first place to put another dollar.

That’s super. That’s great to see those improvements. Thank you so much for the time.

Our next question is from Michael Hall with Heikkienen. Please go ahead.

Thanks, appreciate the time. I just wanted to I guess go back to the completion cadence in the quarter relative to the expectations. It was a little bit higher than what you guys have 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 four quarters, or is there potential that, given that you're kind of moving through completions in a faster order than expectations, it will actually see a higher completion count as we make our way through the year.

This is Herb. It’s really we are 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 are 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, would you potentially drop some activity, or 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 are just executing the plan and what we've laid out, what we are going to do in the second quarter. And then, we will be looking at how to optimize it end of the year. But, at this point, we are seeing no reason to change our number completion for the CapEx field.

Okay, fair enough. And then, can you comment on what the maybe I missed this, but what the average Lateral Length was in the Permian program in the first quarter?

Well, I have it just for the first quarter because it is said that - we have been focusing on the 10,000 for laterals and they have been normally that way 9700, 10,000. So there is some, there is one pad where we did 675 laterals in that simply because least geometry to set that up. So, I will have an average, but it would be by high 8,000 I'm guessing for the quarter.

Okay, that's helpful. And then in the Permian what’s the current run rate on the full drilled completely equipped cost and how it relative to Sweetie Peck and where are those running.

Yes, I think we had that laid out in our last quarter presentation and sometime next on this one. So, you could see what how far they are at the back.

Those numbers include some - our expected cost for this year, so there is a little bit of inflation actually in those numbers.

Turn to Slide 19.

Turn to Slide 19.

Sorry, I missed that, thank you. And the last one is just, in the Eagle Ford I think there was 17 completions what was all in that 1Q '17 completion area that was highlighted I guess its Slide 13 and - 17 in that area where they?

No, that's six certainly borrow away 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.

Okay, great. Appreciate it, thank you.

Our next question is from Paul Grigel with Macquarie. Please go ahead.

Hi, good morning guys. On the uptime percentage an interesting point there, would you guys view as the repeatability of that moving forward drilling by the technology. And would have modeled into these assumptions of guidance as you look out for the rest of the year in that regard?

Okay. So, on uptime percentages we have seen progressive improvement everywhere and that's where it is systems based. And it's sustainable when we are basically in an area, if you have an offset operator flattening your way with well, that's drops time. So a very programmable if you can plan out pretty well what's going to happen for where operations are affected by other operators or your own operations. So, I would say sustainability is there from the system standpoint what we have to plan out and what you put into your guidance is really what you know in your program is effective. So, I think we have planned that out and its quite detailed. So, it's really hard to put that number out statement on that.

Okay, that's understandable. That'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 to the greater extent?

Yes, Paul. We have added some hedges as I said and you can see that. I think what you should expect is, we will be very focused on kind of the more near term for the next couple of years especially during the periods where our leverage is highest. So, it will just be a quarter-to-quarter thing but we look at the volumes and how comfortable we are. It's actually much more than that. I wouldn’t anticipate adding a significant amount of hedges if you look out to the third, fourth and fifth year from any point in time.

Okay, great. That's makes sense. Thanks guys.

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

Yes, thanks for taking my questions. On Slide 13 of your presentation, you heard production on a two stream basis, what does it look like on a pretty stream basis and can you quantify what sort of we could see from that?

Yes, Bryan, I appreciate the question. I don’t think we’ll tackle that one here in the call because I am not good in doing math in my head like that so if you might follow-up with Jennifer following call I appreciate that and we don’t give you VARs on well like this we terrific wells they perform really well and achieve over 150 days it’s great set of wells.

Thank you.

Our next question is from Anthony Diaz with Raymond James. Please go ahead.

Hi, good morning, thanks for taking my question. First up I was just looking to see if you could give us an update on the wiper well I know we are falling back in February and we’re expecting maybe next couple months from to get some kind of indication of what you guys answered that first I guess.

Well Antony I am not sure where you got the information we have flown back in February we recently completed well and we just started flow back we don’t have any data to share with you because it’s just way to early again I am not sure where that February think came from.

Okay, yes. My apologies then yeah and then from there that Martin County block do you guys have just Red Cross for border what kind of data do you guys have and do expect any drilling on that in 2017 I know gave Kevin just across to have paper some all are et cetera.

Yes, Herb. So we’ll be getting to that and late in the year putting a rig put there I don’t know whether we got completion that will be done after this year but it may close.

Okay, all right, that’s fair. And just my last question that 1300 acres just minus where are your focusing those swaps and those trades and kind of going forward where you guys looking specifically?

So there is really two things one is swaps one is to get to the longer laterals where we can figure the acreage to get 10,000 foot laterals fit in there and then the others 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 it’s kind of out there in thicker places and played out to the logical operator in exchange for an operative wells looking interest in acreage and our RDC use so it’s very logical and we got three operators out there everyone is trying to do same thing and makes good business sense.

Okay, that great. Thanks guys, great quarter.

[Operator Instructions] The next question is from Biju Perincheril with Susquehanna. Please go ahead.

Thanks, good morning. In your January presentation, you showed a couple of slides with boundaries for Lower Spraberry and Wolfcamp B. And first, I was wondering if there's any update to those maps. And second, you had plans for drilling at Wolfcamp B or Lower Spraberry wells on that Southeast portion of our acreage in Howard County.

Biju, this is Herb. So first of all, no, we haven’t issued any OpEx to those now, however as you are aware with that, at this level there is a quite bit of industry activity and if you’re watching the railroad commissions reports, we feel that there is periodically new wells out there and those in some cases will be expanding what we’ve been as kind of confirmed areas within our sweet spots. And in particular you may notice those one well, well which was quite a railroad commission I believe yesterday, which looks to have move the Wolfcamp A confirmed contrast based on the IP given to that well quite a bit east. So we’re going to keep modeling those and at a logical point 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 eastern side of your acreage?

It’s in our plan for late this year. So we don’t know whether we get production in this year but at least have the rig on it.

Thank you. Great quarter.

Our next question is from Chris Stevens with KeyBanc. Please go ahead.

Hi guys, good morning. Just a quick follow-up on wiper well question Let me complete one well on that area or are you going to have multiple wells tasking couple of different zones, maybe completing at the same time?

Yes, this is Herb. We just completed the one well, and as Jay mentioned we are just started to pull back on it now.

Yes, just note that number of well, Herb mentioned is only four mile, four to five miles to our west. So, I mean, clearly, you know, we've got a great, well, good looking county section out there and we are cautiously optimistic there, we just don’t have any data yet to share on the wiper, so.

Got it. And then just in terms of the optimization of the development plans in Howard County, you guys want to test the offer to spacing. So, is there any color you guys can provide on what sort of down spacing tests you guys are going to do this year?

Yes, I think you will see that we are - so far we have got quite a few what we have done tests staffed Lower Spraberry, Wolfcamp A, Wolfcamp B and you will see as we proceed through the program this year we will be doing at different stagger configurations which tighten the spacing but in the staggered manner where we've fit pay. So, you will be seeing those results coming out as we go through the year.

Okay. Got it. Thank you.

Our next question is from [indiscernible] with Stiefel. Please go ahead.

Hi, good morning guys. I apologize if you have addressed any of this, I missed the first part of the call. Was interested in the - about the core data that you collected both in Sweetie Peck and Howard County, you are wondering - if you could compared and contrast maybe the few areas and I think you’ve done at this point some spacing cash in Sweetie Peck wondering based on that data that you have seen isn't that applicable to Howard County as well?

Okay, Mike there is a quite a few things you put in there. So, first the core data we are just acquiring the core now the new core, we have considerable core from actually from the benefits of operations RockStar and QStar. So we've got that data, we got correlation with logs that’s well in hand. Now we are getting core through the full section. So, we are able to look at more prospectively and that's off rig and build inventory we hope. So, that's - the ones I just mentioned the 4400 feet RockStar and 59 feet of Sweetie Peck we don’t have that core yet, from one well at RockStar that we just finished. The spacing at Sweetie Peck - certainly everything we have learned at Sweetie Peck completion design recipes that we have been applying that at RockStar and it’s been great for us. We are - 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 and the staggered manner. And we 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 are comfortable with the spacing that you are using with Sweetie Peck and if so can you remind me what - where you settled there?

Yes, that depends on the individual horizon and how quick it is. So, you have to look at how much oil in place is in the mineral and that drives how tight is your spacing is. So, it's one of the things we went over that January call and kind of those fundamental things that really matter. So, its driven by the oil in place how tight and its really the volume that we attribute to a well, that drives what the spacing is, so it isn't so much, it’s just the spacing as you start from the 8 well per section and then you tightened it as there is more volume in price.

And I think if I remember correctly, we had 12 wells in part of Sweetie Peck in Wolfcamp A?

You think 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, I don’t know what Wolfcamp A we ramped on.

I think this is Jay, I think one of the interesting differences between the western and eastern, I think here is where your frac varies are, if you heard that I guess - my impression is to make sure, that I’m right on this, in Howard County area, you probably A, B is probably kind of co-developed as opposed to Sweetie Peck where we are really kind of co-developing Lower Spraberry and the A together. And I think as you get to eastern tower base and the A, B is more of a - I’ll call it a tank in the Lower Spray and the Spray is sort of tank is close to the west side where, there is really no well frac there between the Lower Spray and the A. So there are some differences and we are learning a lot. We have those four 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 on Howard County as well.

Very good. Thank you, guys.

At this time I'm 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 to you next quarter. Thanks.