Good day, and welcome to the Halcon Resources First Quarter 2018 Earnings Call. Today's conference is being recorded. At this time, I'd like to turn our conference over to Mark Meis. Please go ahead.
Okay. Good morning and thank you. This conference call contains forward looking statements. For a detailed description of our disclaimer, see our earnings release issued yesterday and posted on our website. We've also updated our investor presentation for the Q1 and other operational items, and that can be found on our website as well.
I'll begin the call with some comments regarding the financial performance for the Q1, and then I'll turn the call over to Floyd. Production for the Q1 averaged 10,000 167 barrels of oil equivalent a day comprised of 70% oil. The production rate is consistent with the midpoint of production guidance that we provided earlier this year. This production rate represents a 75% growth rate from the Q4 of 2017. We expect continued strong production growth for the remainder of the year.
Our realized first quarter oil differential of 99% of NYMEX is better than the 95% differential seen in the Q4 of last year as prices continued to strengthen. And our natural gas differential came in at 87% in NYMEX, which was higher than the Q4 and driven by weather related demand for gas. Our NGL differential for the Q1 came in at 41%. Our LOE and workover expense came in at $6,300,000 for the quarter, which equates to $6.36 per BOE. This included approximately $700,000 of third disposal charges in Hackberry Draw.
These charges were the result of our producing excess water at a kind of a peak rate for a number of weeks as a few wells were flowing back after fracking. We expect 3rd party water disposal costs to be lower going forward, which when coupled with a rapid rise of production will result in lower LOE and 1 quarter expense per BOE. And we do expect to end the year around $4 per BOE for this metric. Gathering and other expense, as adjusted in our press release, totaled $5,500,000 for the quarter or $5.55 per BOE. We also expect this expense to trend down on a per BOE basis for the remainder of the year as we continue to gain scale.
We expect further improvement in gathering costs going forward as we transition from treating recycled water using a third party contractor to performing this in house, and this could result in as much as $500,000 per quarter in savings going forward. Regarding this cost metric, we would expect to end the year around $3 per BOE. G and A expense, as adjusted for selected items, totaled $11,200,000 for the quarter, and we expect cash G and A for the full year to be between $40,000,000 to $45,000,000 That's in the guidance table in the press release. And based on the current 2018 business plan, there will not be any significant hiring or other G and A activities. With respect to D and C CapEx, we incurred $116,000,000 during the Q1.
We also invested $38,000,000 into infrastructure and seismic. The majority of those dollars are related to infrastructure development, both in Monument Draw and Hackberry Draw, where we continue to accelerate the development of our water infrastructure and gas gathering assets. We also invested $112,000,000 in acquisition activities, the majority of which was the exercise of our Monument Draw option in the North. As far as hedges are concerned, we have right at 10,700 barrels a day of oil hedged at an average price of $52.92 per barrel for the last 9 months of 2018. We also have 14,000 barrels per day of oil hedged in 2019 at an average price of $55.76 Regarding basis differential swaps, we have seen a dramatic rise in the value of our mark to market to write out about $50,000,000 in a relatively short period of time.
As such, we recently decided to bring that value forward, monetize these positions for the second half of twenty eighteen and for a portion of these in 2019. These oil hedge monetizations generated $30,000,000 of cash proceeds to the company. And after these monetizations, we still have 12,000 barrels a day of mid Cush basis hedges in place for the full year of 2019 at an average discounted price of $3.02 a barrel. We do plan to periodically layer in new hedges for the second half of twenty eighteen as we believe there will be opportunities to do so in the near term. On the gas side, we currently have 7,500 MMBtu per day of gas hedged for the last 9 months 2018 at an average price of $3.16 and we have 5,000 MMBtu a day of gas hedged in 2019 at an average price of $2.81 We also have 10,000 MMBTU a day of Waha basis hedges in place for the second half of twenty eighteen through year end 2019 at a discounted price of $1.05 per MMBtu.
As of the end of the quarter and pro form a for the closing of the West Quito acquisition in early April and taking into consideration our new borrowing base of $200,000,000 which increased from $100,000,000 and the recent hedge monetization, we have liquidity of $410,000,000 which is ample amount of dry powder to execute and operate the company. And with that, I'll turn the call over to Wood.
Thanks, Mark. First, a few comments about rigs and frac spreads. Our 4th operated rig will be here in a few weeks. We'll drill a couple of wells with it at Hackberry Draw. Then as we finish our 3 d seismic work at West Quito, we'll move this 4th rig there in July.
This also allows us to finish up some additional seismic work at Hackberry before we move rigs back down there. Other 3 operated rigs will spend most of the rest of 2018 2019 in Monument Draw in West Quito, but we'll bounce back down to Hackberry from time to time. We continue to have one full time frac crew working for us. This frac crew can't keep up with 4 rigs. So we'll bring in spot crews as needed to keep our DUC inventory low.
Our guidance includes the addition of a 4th rig here in later this month and the impact of our West Quito acquisition, which won't really be felt till late in the year, We won't start drilling there until about July, as I mentioned. Our full year production guidance midpoint is higher than the previous guidance. This is reflective of the additional rig and the some West Quito production. Our 2018 production profile is back end weighted due to our rig and frac schedules. As we shift capital to Monument Draw as we already have been doing, this also causes production to be back end weighted, Monument Draw wells take longer to drill, so they have longer cycle times.
We make great wells there though as you know. Guidance, of course, is highly dependent on spot frac crew timing. Hence, we've given a bit of a range there. We'll end 2018 quite strong with an exit rate of well over 25,000 BOE per day and Q4 will be quite strong accordingly. Of course, we've already planned our program for 2019.
We're planning to run 5 rigs for most of 2019, spend less than $550,000,000 on drilling CapEx, drilling completion CapEx and produce about 35,000 barrel oil equivalent per day and exit the year well over 40,000 barrels of oil equivalent per day. Our spend on infrastructure will have moderated somewhat by 2019. At this time, we look to spend about $30,000,000 or so on moving natural gas water and crude to the appropriate points of delivery. Costs have been quite a story this year, obviously, to us and others, drilling and completion costs are higher due to recent cost increases. We're working hard on ways to lower current costs without compromising production.
We're looking to cut costs, not corners. LOE and gathering transportation and other per BOE were higher also. This is somewhat driven by the inclusion of West Quito, which is gassier. Our projections, I should say, for LOA and GTO are higher because of the inclusion of West Quito, which is gassier and has a more costly gathering fees in some of the areas. And higher general operating expenses in the field, we've experienced also things like trucking, contractors, ropes, open dope, all that kind of stuff.
Acquisitions, we aren't looking at anything at this time. We're focused on execution of our existing program. We are exploring ways to improve liquidity and capacity all the way from JVs to the sale or partial sale of our awesome infrastructure company, Halcon Field Services. We may or may not decide to pursue these ideas. We're in the early stages of thinking about all of this.
In any case, we have absolutely no plans to sell equity at this time. In the slide deck posted last evening, we've included a detailed slide highlighting our takeaway contracts and longer term plans on egress from the basin. We feel good about our arrangements in the Delaware Basin. They're all designed to move our production past anticipated choke points. We'll have most of our oil on pipe and off of trucks within the next few months.
And on the gas side, we have multiple options to take our gas from our leasehold and to various processing facilities at reasonable prices. We're in a, again, kind of a vicious cost increase cycle. Good news, oil has stayed up pretty well. So those things typically tend to go hand in hand. While we're highly focused on capital efficiency, we own long term durable assets and we can't really afford to be short sighted in their development accordingly.
We will continue to spend capital in geoscience and other sorts of technical endeavors, including 3 d seismic, microseismic tracer surveys, drilling pilot wells, running shuttle logs and using other tools to fine tune the development of our great property. Additionally, I should point out, we are drilling only long laterals and we are testing new ways to frac these long laterals. The combination of investing in geoscience, drilling long laterals, testing frac results and focusing our spending on Monument Draw in West Quito is the right thing to do, but expensive. We are driven to develop our assets in the most appropriate and most technical manner. This is surely the best for all of our stakeholders.
We're set to move ahead. We have a great year laid out ahead of us and a very exciting 2019. Our current plans lead to substantial economic growth, cash flow sufficiency and value. Operator, if we have any questions, we'll take a few right now.
Our first question comes from Jason Wangler from Imperial Capital.
Good morning, Floyd. Thanks for the color heading into 2019. If I heard it right, as far as just kind of thinking about the rigs, effectively 3 running in Monument Draw, effectively the rest of
this year and one kind of
bouncing back from West Quito and maybe going to Hackberry a bit. Is that correct? And then as you look at 2019, how should we kind of think about the positioning?
Most likely, once we start at West Quito, we'll keep that rig there. So one rig might bounce a little bit between Monument and Hackberry, but we don't have too many wells planned. I don't know the exact number, 2 right away and then another couple later in the year. So primarily at 2 to 3 rigs at Monument and 1 rig at West Quito. We're just receiving some 3 d seismic down in Hackberry, which we think will help us fine tune.
We're getting great results down there, but we think they can be improved with a little help from the seismic. So we're using this pause to finish that work.
Okay. And then as you look at you mentioned not looking at M and A in a big way, but with the West Quito pad there and I think in the slides you discussed the fact that you're sort of looking to block that up and getting the long laterals and your affinity for those. Is there an opportunity to either pick up some small pieces there to allow those long laterals? Or is that simply more just a function of getting with the partners that have the acreage nearby?
It's a combination. We are in contact with everyone that would complete picture that would allow us to drill all long laterals, but we've got plenty of land to go ahead and drill this year's program up there with only long laterals. So it's a process that doesn't require a lot of speed. There might be a few small leases to buy or some trades to make or just some let's sign a JOA and drill the well together, which we're happy to do with all the great people that work out where we work.
I appreciate the color. Thank you.
Our next question comes from Tarek Hamed from JPMorgan. Please go ahead.
This is Kevin Kwan actually on for Tarek. Thanks for taking my question. Just wanted to get some more detail. I know this is a little while ago, but on just on the Monument East option Monument Draw East option. I know you guys decided not to exercise that, but just want to see if there's any maybe read through to sort of the eastern portion of your current volume and draw position?
Well, Kevin, as you may remember that we made one of the best wells in the entire area, the furthest east most well we've drilled. So the land east of there, we didn't undertake the option on, but this well and some pilot holes we've built have totally proved up all the rest of our land in our opinion. We decided not to undertake the option, as we said before, because there were to be fewer landing zones as we move east, but still perhaps a good landing zone as we found with our 5,901 5,902 well in Section 59. So the read through would be that we've done the kind of work we always do. We drill pilot holes.
We test the edges of all of our property in the middle, and we're good to go with what we've kept. So we're still left with about 60,000 acres in the basin. Forget how many up here, but a good 25 or 30 right up in the between Monument Madron and West Quito up in Ward County.
Okay. That's helpful. And then just moving on to your oil mix. I know you're at about 70%. Just wanted to get a sense of how that might change as you move into accelerate West Quito Draw activity.
I think some of those wells tend to be a little bit gassier. I know you have a range of 68% to 72% out there. Should we expect that to just get closer to the gassier side the year goes
on? We won't have that much actual input from West Quito. But by the time we drill wells and get them fracked and get them on production, it takes a couple of months to get that done on each well. So our current estimate is good for this year. It will be a little less in 2019 and I don't have an exact number, but maybe think about 65% instead of 70% for 2019 crude versus NGLs plus gas.
So yes, 8 wells out there. Remember, you might make wells that are in the 1,500,000 or 2,000,000 barrel BOE range at Monument Draw that are round numbers of 80% oil. At West Quito, you might make wells that are 2,000,000 to 3,000,000 barrels equivalent that are only 50% oil or 55 or something like that. So you still make we've got a great slide in the presentation that points out that you still make a tremendous amount of oil at West Quito, just a lot more gas.
Okay, understood. Makes sense. And then finally, just my last one, just on service costs. I know that you had some good detail in your prepared remarks. Just wanted to see specifically maybe what the vendor how your conversations have been with vendors and what services have been in shorter supply more specifically?
So look, we have great relationships with all of our suppliers and our contractors that supply rigs and frac spreads and pipe and all these things, wireline, coiled tubing. So our conversations are great with them. It's driven by scarcity. The scarcity is caused by more rigs moving in the region, more rigs lead to more wells that need to be worked. And so there's a bit of a scarcity factor and that's it's America, right?
So people raise their prices when their product is in demand. We understand that and at times it's been the other way in our business. So our conversations have been that we look kind of steady now on frac spread costs for this year. We don't know that for sure. We've got one of our rigs is under contract.
We may put another rig or 2 under contract. It's we had such an increase over the past 6 to 9 months that it does seem to have moderated, but there's no way to promise that or to totally plan it. Accordingly, we've tried to make some adjustments in our projections for a bit of cost inflation. And we're also working in ways to lower costs. Again, as I mentioned in my little speech a minute ago, lower cost but not cut corners.
If you listen to the calls and read the information from our partners on the supply side of our business, they suggest prices might go up some more. So it's hard for us to know that. We're growing towards scale. We don't really have anything you could call scale now, but once you get up in the 30000, 40000 barrel a day range and you're running several frac spreads and multiple rigs, you have scale and you have a little a bit more bargaining power with all of your partners on the service side of our business. So we're heading that way.
Okay. And then I guess with that too then, what's your average like duration for most of your contracts with the services partners? And is there are you guys looking into extending those even further?
We're looking at it all the time and we're certainly looking at it now. Most of our contracts are, hey, we'll stay with you if you'll pay the going rate. That doesn't sound very good, but we hire the best people everywhere we work. And we understand that the best can demand more money and we pay their way. We have so few breakdowns.
We have so few screen outs because somebody's equipment is broken down. We don't have people that show up late and leave early. So there's a certain amount of quality built into the way that we run our field operations that I mentioned before. We don't use the low bidder. We use the people that we want that have the right field people and the right iron on hand.
So rigs and frac spreads are the and of course, you buy pipe, but we buy pipe by the 1,000 and 1,000 of feet even now. We have one rig under contract. We're looking at putting another 2 under contract. And these aren't long, long term contracts, they're a year or 2. Frac spreads, we're starting to have those conversations, but we're pretty comfortable with where we are right now.
It's expensive.
Our next question comes from Mike Kelly from Seaport Global. Please go ahead.
Hey, guys. Good morning. Your Q4 guidance implies that your production trajectory is going to be picking up steam as you enter 2019. And I just would love to get a sense for how you think you're set up for next year. I think previously you had put out in slides in February, 30,000 barrel a day number for 2019, but this was predicated on a 5 rig program.
Just curious how you see these assumptions if they're still good?
I think I mentioned on the call that we're looking to produce about, let me check, make sure, produce about 35,000 barrels a day now for 2019 on average and exit the year well over 40,000 barrels a day. This is just driven by the mix of more Monument Draw wells, more West Quito wells and we're making great wells at Hackberry, but fewer of those and 5 rigs.
Okay. I appreciate that. Is that something or too late?
Yes. We're expecting our path, which is slightly back end weighted this year, to be a fairly smooth upward trajectory in terms of production. And we've got the rigs on hand and we're already experiencing that as you know. Myak, we were basically a start we were basically a start up about a year ago with 3,000 barrels a day or 3,500. So we're moving mountains to make our numbers.
Got it. And then, Floyd, you mentioned in your prepared remarks that you would consider a JV or even a sale of your infrastructure. And I just would love to get some added color here. I'm really just kind of curious of the ideal structure, size, timing, etcetera. Thanks.
Yes. There's no real comment on timing. We're not driven to do anything. We view those things as a cost of capital analysis and compare it to what we could do with that capital and could we earn significant rate of return based on the cost of that capital. JVs are readily available these days and sometimes they have a great spot.
We built a very valuable infrastructure company, Alcon Field Services, and we could sell half of it or all of it to someone and maintain some control and bring a little money in that way. So we're looking at these things. We're not rushing into any of that. We get a lot of incoming on those subjects. And so we felt we just felt like it made a lot of sense make sure that we've got those things analyzed and understand exactly the cost and the ramifications of doing any of that kind of activity.
That's a little vague, but we just don't have anything right on the front burner right now.
Our next question comes from Jacob Gomolinski Ekel from Morgan Stanley. Please go ahead.
Hey, good morning and thanks for taking the questions. On the Q2 production guide, given you're already producing 13 500 a day, is the guide a cycle time issue due to the focus on long laterals? Or is there an element of conservatism in there?
Well, listen, we do a workmanlike job of trying to project these things out. Trying to remain conservative so that maybe we'll beat some of these numbers instead of just make them. As you move from wells, it might take you 20 or 22 days to drill to more wells that might take you 40. There's just a whole cycle time thing that goes on there for sure.
Got it. So was Q1 not as focused on the 9,000 plus foot laterals as Q2 and onwards going to be?
No, we've only drilled one short lateral the entire time we've been in the Delaware Basin. That was our 1st lateral at Monument Draw. So no, we're drilling long laterals. I'm just pointing out that in we've had a heavier weighting in the past towards Hackberry, made great wells there and they're all long laterals. We got him down to John's on the phone, but I think less than 25 days start to finish and the wells at Monument Draw are taking 40 days or 42 days.
It's harder drilling.
And sorry if I missed it already. Do you have some color on what's driving that increase in cycle times in the Monument versus in Hackberry?
It's really just more rig days per well. Once the drilling part is finished, the rest of it takes about the same amount of time as it would anywhere else, the frac job and all that. We get about as many frac in one day as we do in either area. It's really just the drilling days. There's we've experienced a few problems at the hole, probably more problems in that area that actually cost quite a bit of time before you even get into the curve.
Got it. And then, it looks like you'll have a fair amount of spare capacity on the water handling front. Is there any potential to add 3rd party volumes to that infrastructure for some sort of fee? Or does that location not really lend itself to that?
Actually, we get a lot of incoming about that as well. It's been such a quick build for us that we would hate to sign up a customer if you'd call it that and not be able to service them. So that's certainly in the realm of possibility. Right now, we're looking to make sure that we can service all of our own needs well and on time. And that's kind of our driving thought process right now.
No, that definitely makes sense. And then I guess lastly, you mentioned you are evaluating ways to improve liquidity either JVs or a potential sale of that infrastructure. Can you talk about the motivation behind that given you do have $443,000,000 of cash and an undrawn revolver?
The motivation is that we've had a lot of incoming calls from both actual participants and from banks and we thought it was incumbent on us to understand the economics of that quite well and see how it would pair with what we do. They're 2 completely different things. The infrastructure company is just a matter of it's got EBITDA and if you want to try to sell something like that and bring some of your EBITDA forward just like any asset. The other business is the cost of capital versus if you freed up some capital, what could you earn with that capital that you freed up. And so we're just we're really we thought we should mention it because we're looking at it.
We're not in a rush and we haven't made any decisions.
Got it. Okay. Thanks very much, Budd.
Our next question comes from David Beard from Coker Palmer. Please go ahead.
Hey, good morning, gentlemen. Thanks for the time.
Hey, there.
Most of my questions have been asked, but it really I wanted to just touch base on well costs as you look into 2019 or even 2020. Do you plan on moving, for lack of a better term, into production mode, which way may give you some ability to scale down some cost? Or do you still think you'd be in full science mode for next year? Or how should we think of the 2019 2020?
I'd like John to address part of that question, but we're going to always be in full science mode. These assets, these wells are so expensive and the prices are so large, millions and millions of barrels from single wellbores, we're always going to be analyzing how we can fine tune what we're doing. However, we will be shifting to development mode, which is more multi well pads over time. And John, I think you probably have some numbers, but the savings on that can be quite substantial.
Yes. Thanks, Floyd. So David, as we move from 2018, a lot of single well pads delineation work, 2019, 2020 multi well pad development. Our positions will be fully delineated with and we'll have a good idea of what our baseline production is from each well. At that point, we can start turning the dials as you per se, with regard to different aspects of completions.
That may be sand volumes, that may be in basin sand versus the white sand we predominantly use. I will comment that we are utilizing brown sand in our 100 mesh volumes at this point. But there's a lot of dials there. We can turn not only on the completion side, on the drilling side, once again, taking advantage of those batch drilling opportunities with those multi well pads. And obviously, on the facility side, Monument Draw, we're producing into our central production facility.
There's a large impact there, whereas we're not building those individual well facilities at this time. So there's going to be quite a transition. You can think about that from a different number of different avenues. So we don't know what the market is going to look like from the cost side, but there's going to be a lot of opportunities internally to drive down costs as we move forward.
Our next question comes from Ron Mills from Johnson Rice. Please go ahead.
Good morning, Floyd. I may have missed some of the background here, but you're clearly moving more capital towards Monument Draw from Hackberry Draw. But if you think about the wells to be placed online in each of those areas, how much activity have you shifted to Monument Draw from Hackberry Draw?
Ron, it's more in the planning aspect that we've shifted. We still got some wells to be fracked there. We haven't I don't think there's a rig drilling there today, but there was we finished the well just a couple of weeks ago there. So it's more in the projections of all of that. We're still exceeding our type curves in both areas and our type curves are quite commercial.
So we fully expect to be back at Hackberry. We're getting some seismic in just now and we'll have finished our internal work on that seismic by midsummer here. And we expect that we can further aid our efforts in Hackberry as we've done already in Monument Draw with the seismic. And that's one of the main reasons we've delayed moving the rig up to West Quito. We'll have some new seismic work that we got it in house now.
We'll have finished our work on that by midsummer. We'll move a rig there at that time. So if you look at the Q4, we'd probably only be drilling a couple of wells at Hackberry Draw and 8 wells at least between West Quito and Monument Draw.
And the shift from Hackberry to Monument Draw, what was the what's driving that more than anything? Are you waiting on some of the new seismic? Is it just well results and returns at Monument Draw you're seeing as being better? Or is there something else?
Oh gosh, the 90 day IPs are 30% higher. That's a round number at Monument Draw versus Hackberry. Hackberry is wonderful, but the returns are just higher. It's a simple matter. We don't have any real exploration issues anywhere.
So we've migrated the capital towards the highest rate of return.
Okay. And then I appreciate the comments on the 2019 production and CapEx and as you know that product mix change as you have more West Quito. How do you think that that capital splits between West Quito, Monument Draw and Hackberry Draw? You think you'll still have more of a focus at Monument Draw and West Quito? Or what should we think about that?
For sure. It will be if plans hold up and we run 5 rigs for a lot of 2019, a rig will deliver about 12 frac and put on production wells in a year. That's like 60 or 65, 70 wells somewhere in there, you'll find that probably less than 20% will be from Hackberry. And again, it's just because the other areas offer a higher rate of return, higher IPs and higher reserves. And again, it's not Hackberry is doing great.
It's just if you took if you tried to split the money that I mentioned and it's an estimate at this time, Early guidance would be out of $550,000,000 be maybe about $100,000,000 at Hackberry and 300 at Monument and maybe 75 or 100 at Hackberry.
Monument, West Quito.
I mean, West Quito would be 150 Monument, maybe 300 and maybe 100 at Hackberry, round numbers.
And how does that plan leave you in terms of acreage being converted to HBP in each of those areas as we look into 2019?
Well, if I deal with them separately, I think we have to drill 3 wells pretty quickly at West Quito to take care of our needs for about a year and another 3 or 4 wells and we'll do that anyway. We're way ahead of the game at Monument. I mean, we only have to drill a couple of wells a year. And at Hackberry, we're just about taking care of most of our expirations with our drilling we've already done. So we're really not none of this is driven by expirations.
It's all driven by capital efficiency.
Great. Thank you for all the color.
There appears to be no other questions. At this time, I'd like to turn the conference back to our speakers for any additional or closing remarks.
Well, thanks. We've outlined a pretty exciting balance of 2018 and a screaming 2019. I hope you all got your questions answered and please call us if we think of something we didn't talk about. Thank you.
This does conclude our conference for today. Thank you for your participation. You may disconnect.