Good day, welcome to the Halcón 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 Meier. 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, posted on our website. We've also updated our investor presentation for the first quarter and other operational items, that can be found on our website as well. I'll begin the call with some comments regarding the financial performance for the first quarter, I'll turn the call over to Floyd. Production for the first quarter averaged 10,967 barrels of oil equivalent a day, comprised of 70% oil. The production rate is consistent with the midpoint of the production guidance that we provided earlier this year. This production rate represents a 75% growth rate from the fourth quarter of 2017. We expect a continued strong production growth for the remainder of the year.
Our realized first quarter oil differential of 99% in NYMEX was better than the 95% differential seen in the fourth quarter of last year, as prices continued to strengthen. Our natural gas differential came in at 87% in NYMEX, which was higher than the fourth quarter, driven by weather-related demand for gas. Our NGL differential for the first quarter came in at 41%. Our LOE and workover expense came in at $6.3 million for the quarter, which equates to $6.36 per BOE. This included approximately $700,000 of third-party water disposal charges in Hackberry Draw. These charges were the result of our producing excess water at a peak rate for a number of weeks, as a few wells were flowing back after fracking.
We expect third-party water disposal costs to be lower going forward, which when coupled with a rapid rise of production, will result in lower LOE and workover expense per BOE. 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 $5.5 million 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, this could result in as much as a half a million dollars per quarter in savings going forward. Regarding this cost metric, we would expect to end the year around $3 per BOE.
G&A expense, as adjusted for selected items, totaled $11.2 million for the quarter, we expect cash G&A for the full year to be between $40 million-$45 million. That's in the guidance table in the press release. Based on the current 2018 business plan, there will not be any significant hiring or other G&A activities. With respect to D&C CapEx, we incurred $116 million during the first quarter. We also invested $38 million 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 million 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 nine 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 right at about $50 million in a relatively short period of time. As such, we recently decided to bring that value forward and monetize these positions for the second half of 2018 and for a portion of these in 2019. These oil hedge monetizations generated $30 million of cash proceeds to the company.
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 2018, 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 nine months of 2018 at an average price of $3.16. 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 2018 through year-end 2019 at a discounted price of $1.05 per MMBtu.
As of the end of the quarter, pro forma for the closing of the West Quito acquisition in early April, taking into consideration our new borrowing base of $200 million, which increased from $100 million, the recent hedge monetization, we have liquidity of $410 million, which is an ample amount of dry powder to execute and operate the company. With that, I'll turn the call over to Floyd.
Thanks, Mark. First, a few comments about rigs and frac spreads. Our fourth operated rig will be here in a few weeks. We'll drill a couple of wells with it at Hackberry Draw. As we finish our 3D seismic work at West Quito, we'll move this fourth 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 three operated rigs will spend most of the rest of 2018 and 2019 in Monument Draw and 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 four rigs, so we'll bring in spot crews as needed to keep our DUC inventory low.
Our guidance includes the addition of a fourth 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 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. Fourth quarter will be quite strong accordingly. Of course, we've already planned our program for 2019. We're planning to run five rigs for most of 2019, spend less than $550 million on drilling CapEx, drilling completion CapEx, and produce about 35,000 barrel of oil equivalent per day, and excuse me, exit the year well over 40,000 barrel of oil equivalent per day. Our spend on infrastructure will have moderated somewhat by 2019. At this time, we look to spend about $30 million 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 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 for BOE were higher also. This is somewhat driven by the inclusion of West Quito, which is gassier. Our projections, I should say, for LOE and G&T are higher because of the inclusion of West Quito, which is gassier, and has a more costly gathering fee than some other areas. Higher general operating expenses in the field we've experienced also, things like trucking, contractors, rope, soap and 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, Halcón Field Services. We may or may not decide to pursue these ideas.
We are 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. 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 vicious cost increase cycle. Good news, oil has stayed up pretty well, those things typically tend to go hand in hand.
While we're highly focused on capital efficiency, we own long-term durable assets, we can't really afford to be short-sighted in their development. Accordingly, we will continue to spend capital on geoscience and other sorts of technical endeavors, including 3D seismic, microseismic tracer surveys, drilling pilot wells, running shale 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, 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 and 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.
Absolutely. If you'd like to ask a question, that is star one on your telephone keypad. If you're using a speakerphone, please make sure your mute function is turned off to allow your signal to reach our equipment. Again, that is star one for any questions. Our first question comes from Jason Wangler from Imperial Capital. Please go ahead.
Morning, Floyd. Thanks for the color heading into 2019. If I heard it right, as far as just thinking about the rigs, effectively three running in Monument Draw effectively the rest of this year, and one bouncing back from West Quito and maybe going to Hackberry a bit. Is that correct? As you look at 2019, how should we think about the positioning?
Most likely once we start at West Quito, we'll keep that rig there. 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. Two right away, and then another couple later in the year. Primarily two to three rigs at Monument and one rig at West Quito. We're just receiving some 3D 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. We're using this pause to finish that work.
Okay. As you look at, you mentioned not looking at M&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 a 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. 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. 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 Tariq Hamid from JP Morgan. Please go ahead.
This is Kevin Kwan, actually. I'm for Tariq. Thanks for taking my question. Wanted to get some more detail. I know this is a little while ago, just on the Monument Draw East option. I know you guys decided not to exercise that, just wanted to see if there's any maybe read through to sort of the eastern portion of your current Monument Draw position.
Well, Kevin, as you may remember that we made one of the best wells in the entire area, the furthest eastmost well we've drilled. The land east of there, we didn't undertake the option on, this well and some pilot holes we've drilled 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, still perhaps a good landing zone as we found with our 5902 well in section 59. 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. We're still left with about 60,000 acres in the basin.
I forget how many up here, but a good 25 or 30 right up between Monument Draw and West Quito up in Ward County.
That's helpful. Then just moving on to your oil mix. I know you're currently 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 gassier. I know you have a range of 68%-72% out there. Should we expect that to just get closer to the gassier side as the year goes on?
We won't have that much actual input from West Quito, by the time we drill wells, get them fracked and get them on production, it takes a couple of months to get that done on each well. Our current estimate is good for this year. It'll be a little less in 2019, I don't have an exact number, but maybe think about 65% instead of 70% for 2019 crude versus NGLs plus gas.
Got it. Okay.
Yeah. Eight wells up there. Remember, you might make wells that are in the million and a half or 2 million barrel BOE range at Monument Draw, that are round numbers of 80% oil. At West Quito, you might make wells that are 2 million to 3 million barrels equivalent that are only 50% oil or 55% or something like that. 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, I understand. Makes sense. 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 how your conversations have been with vendors and what services have been in shorter supply more specifically?
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. Our conversations are great with them. It's driven by scarcity. The scarcity is caused by more rigs moving into the region. More rigs lead to more wells that need to be worked, there's a bit of a scarcity factor, and that's America, right? 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. Our conversations have been that we look 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 a contract. We may put another rig or two under contract.
We had such an increase over the past six to nine months that it does seem to have moderated, 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, we're also working at ways to lower costs. Again, as I mentioned in my little speech a minute ago, lower cost, 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. 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 30,000 and 40,000 barrel a day range, and you're running several frac spreads and multiple rigs, you have scale, and you have a bit more bargaining power with all of your partners on the service side of our business. We're heading that way.
Okay. I guess with that too, what's your average duration for most of your contracts with the services partners, and are you guys looking into extending those even further?
We're looking at it all the time, 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, we hire the best people everywhere we work, 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's broken down. We don't have people that show up late and leave early. 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.
Rigs and frac spreads are the. Of course, you buy pipe, we buy pipe by the thousands and thousands of feet even now. We have one rig under contract. We're looking at putting another or two under contract. These aren't long, long-term contracts. They're a year or two. Frac spreads, we're starting to have those conversations, we're pretty comfortable with where we are right now. It's expensive.
Understood. All right. Thanks so much for your help, Floyd. Appreciate it.
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 a 30,000 barrel a day number for 2019, but this was predicated on a five-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 a fewer of those, and five rigs.
Okay. Yeah, appreciate that.
Yeah.
if I'm a minute or two late.
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, Mike.
Got it.
we were basically a startup about a year ago with 3,000 barrels a day or 3,500. We're moving mountains to make our numbers.
Got it. Floyd, you mentioned in your prepared remarks that you would consider a JV or even a sale of your infrastructure. I just would love to get some added color here. I'm really just curious of the ideal structure, size, timing, et cetera. Thanks.
Yeah, 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 a 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, Halcón 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. We're looking at these things. We're not rushing into any of that.
We get a lot of incoming on those subjects, we just felt like it made a lot of sense to 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.
Understood. Thank you.
That's a little vague, we just don't have anything right on the front burner right now.
Got it.
Our next question comes from Jacob Gomolinski-Ekkel from Morgan Stanley. Please go ahead.
Hey, good morning, and thanks for taking the questions.
Hey there.
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. We're 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. It might take you 40. There's just a whole cycle time thing that goes on there, for sure.
Was Q1 not as focused on the 9,000-plus foot laterals as Q2 and onwards is going to be?
No, we've only drilled one short lateral the entire time we've been in the Delaware Basin.
Okay.
That was our first lateral at Monument Draw. No, we're drilling long laterals. I'm just pointing out that we've had a heavier weighting in the past towards Hackberry, made great wells there, and they're all long laterals. We got them 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.
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 frack job and all that. We get about as many frack intervals fracked in one day as we do in either area. It's really just the drilling days. We've experienced a few problems up hole, probably more problems in that area, that actually cost quite a bit of time before you even get into the curve.
Got it. Then it looks like you'll have a fair amount of spare capacity on the water handling front. Is there any potential to add third-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. 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 our driving thought process right now.
No, that definitely makes sense. 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 million 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 two 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, it's 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? 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, Floyd.
Our next question comes from David Beard from Coker & Palmer. Please go ahead.
Good morning, gentlemen. Thanks for the time.
Hey there.
Most of my questions have been asked, but 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 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? How should we think of that in 2019 and 2020?
I'd like John to address part of that question, but we're going to always be in full science mode. These wells are so expensive, and the prizes are so large, millions and millions of barrels from single well bores. 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. John, I think you probably have some numbers, but the savings on that can be quite substantial.
Thanks, Floyd. 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, 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. 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. 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. There's going to be quite a transition. You can think about that from a number of different avenues. We don't know what the market's going to look like from the cost side, there's going to be a lot of opportunities internally to drive down costs as we move forward.
I know that's helpful. Appreciate the time.
Thanks.
As a reminder, that's star one for any question. Our next question comes from Ron Mills from Johnson Rice. Please go ahead.
Morning, Floyd. I may have missed some of the background here, you're clearly moving more capital towards Monument Draw from Hackberry Draw. 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've still got some wells to be fracked there. I don't think there's a rig drilling there today, but we finished a well just a couple of weeks ago there. 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. 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 at in-house now.
We'll have finished our work on that by midsummer. We'll move a rig there at that time. If you look at the fourth quarter, we'll probably only be drilling a couple of wells at Hackberry Draw and eight wells at least between West Quito and Monument Draw.
In the shift from Hackberry to Monument Draw, 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's wonderful, the returns are just higher. It's a simple matter. We don't have any real exploration issues anywhere, we've migrated the capital towards the highest rate of return.
Okay. I appreciate the comments on the 2019 production and CapEx as that product mix changes, you have more West Quito. How do you think 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, what should we think about that?
Oh, for sure. If plans hold up, we run five 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. Again, it's just because the other areas offer a higher rate of return, higher IPs, and higher reserves. Again, Hackberry's doing great. It's just if you tried to split the money that I mentioned, it's an estimate at this time, early guidance would be out of 550, it'd be maybe about 100 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.
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 three wells pretty quickly at West Quito to take care of our needs for about a year, and another three or four wells, we'll do that anyway. We're way ahead of the game at Monument. We only have to drill a couple of wells a year. At Hackberry, we're just about taking care of most of our expirations with our drilling we've already done. 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 you 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.