PDC Energy Inc (PDCE) 2016 Q3 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the PDC Energy third-quarter 2016 conference call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session, and instructions will be given at that time. (Operator Instructions) As a reminder, this call is being recorded.

I would now like to turn the call over to Mike Edwards, Senior Director, Investor Relations. You may begin.

Good morning, everyone, and welcome. On the call this morning we have Bart Brookman, President and CEO; Lance Lauck, Executive Vice President; Scott Reasoner, Senior Vice President of Operations; and Scott Meyers, Chief Accounting Officer. We've posted a slide presentation that accompanies our remarks today on the Investor Relations page of our website, which is pdce.com.

I'd like to call your attention to our forward-looking statements on slide 2 of that presentation. We will present some non-US GAAP financial numbers on today's call, so I'd also like to call your attention to the Appendix slides, where you'll find the reconciliation of those non-US GAAP financial measures.

With that, let's get started. And I'll turn the call over to Bart Brookman, our CEO. Bart?

Thank you, Mike. And good morning, everyone. A terrific third quarter for the Company. We are exiting 2016 in a very strong position. For the quarter, our production exceeded expectations, primarily driven by the ongoing enhancements of our Wattenberg completions.

Our operating costs continue to show dramatic improvement, and our capital programs are on schedule. We expect total capital spend for 2016 should target the lower end of our guidance range. And from a business development perspective, our acreage swap with Noble Energy closed late in the third quarter, fueling additional capital and operating efficiencies in our Wattenberg operations.

And perhaps most significant, the third quarter brought a transformational acquisition -- a core Delaware position, 57,000 net acres in Reeves and Culberson Counties. And in early September, we entered the capital markets where we successfully raised nearly $1.2 billion. The acquisition is scheduled to close early December, and we plan to enter 2017 with these tremendous Permian assets -- two rigs running in the Delaware, and a balance sheet to ensure we have the financial strength to execute on our capital programs.

Now let me cover some third-quarter highlights. Production was 6 million barrels of oil equivalent or just over 65,000 BOE per day, again beating our internal expectations. This is a 39% improvement from the same-quarter 2015 and a 14% improvement from second-quarter 2016. In this quarter, we spud 16 extended reach laterals or XRLs, and turned the first of these projects online.

Year-to-date, we have spud 35 XRLs. These projects are becoming increasingly prevalent in our Wattenberg operating plan and will become a key part of our 2017 capital budget when blended with the recent acreage swap. These wells provide a more efficient means of producing in the Wattenberg field from both a capital and operational perspective.

Our marketing team's efforts continued to improve our margins in the third quarter, as [deducts] on our oil sales averaged $4.36 per barrel. And from a financial perspective, adjusted cash flow for the quarter was $123 million. Operating costs for the Company continue to improve, as lifting costs came in at $2.33 per BOE. And as I noted earlier, capital spend is in line with our expectations, and total CapEx for 2016 is now targeting $400 million. Scott Meyers and Scott Reasoner will give a lot more detail around this later in the call.

Now, what can you expect in 2017? First, expect top-tier growth. While the Board has not yet approved our budget for 2017, we anticipate a development plan that would allow us to achieve production growth over 30%. We plan on adding one rig in the Wattenberg field in 2017 and one rig in the Delaware. So, we plan to exit 2017 with seven rigs total -- four in the Wattenberg, three in the Delaware.

We expect the balance sheet to strengthen as we go through next year. We intend to begin 2017 with a debt to EBITDA of just over [2] and exit 2017 with a debt to EBITDA of just under [2]. At the end of 2017, we anticipate having an undrawn revolver and cash on-hand.

In Wattenberg, expect the same reliable production growth, technical enhancements on both completions and drilling, ongoing efficiency gains, particularly due to the recently completed acreage swap, a strengthened and expanded organization, and a larger focus on extended reach drilling. And then in the Delaware, we plan to integrate these assets, build out the organization, focus on holding acreage with Wolfcamp A and B horizontal drilling programs, begin the process of understanding additional benches outside of the Wolfcamp.

And as we move towards the end of 2017, expect multi-well pads to become a larger part of our operating model. And last, by midyear 2017, we intend to fully define our midstream asset strategy for the Delaware.

So, in closing, I want to thank all of the PDC employees for their efforts; an outstanding quarter. We delivered strong operating results and, at the same time, announced this significant acquisition, a job well done. As we enter 2017, PDC begins a new era of growth with our ongoing Wattenberg performance, and now our emerging Delaware assets.

With that, I'd like to turn the call over to Scott Meyers for a financial overview.

Thank you, Bart, and good morning, everyone. For more detail on the material we are presenting today, please be sure to check out the third-quarter 10-Q and press release, both which were filed this morning. I'll touch base on a couple of the highlights from the quarter before giving a brief overview of our balance sheet and current hedge position.

For the third quarter, sales were approximately $142 million, a 36% increase compared to the $105 million for the third quarter of 2015, and an increase of nearly 30% from the second quarter of this year. Our Q3 to Q3 increase is due to production growth of 39% with our BOE pricing essentially flat.

LOE expenses, which Scott will touch on in more detail in a minute, was extremely strong for the quarter, coming in at $14 million or $2.33 per barrel. This represents a slight increase on a total dollar basis compared to the third quarter of 2015, while our LOE per BOE decreased from $3.20 or 0.27% in that same time. Included in our net loss for the quarter are several one-time nonrecurring expenses related to our Delaware Basin acquisition.

Fourth, G&A for the quarter was $32.5 million, represents an increase of $12.2 million when compared to the third quarter of 2015. $11.3 million of this increase relates to the sum of the aforementioned acquisition-related fees and expenses. Excluding these fees, G&A on a BOE basis decreased 25% year-over-year to $3.53 per BOE compared to $4.69 in the third quarter of 2015.

Next, our interest expense, which is not shown here, but was $20.2 million in this quarter. This compares to $12.1 million in the third quarter of 2015. The $8.1 million increase year-over-year is due to an approximate $9 million charge related to our short-term acquisition financing, which has since been replaced by our permanent financing, which will be discussed in a minute.

Moving to slide 8, I'll highlight a couple of the non-GAAP metrics. Please keep in mind that detailed reconciliations of these numbers can be found in the Appendix. Adjusted cash flow from operations and adjusted EBITDA can be seen both on the table and on the graphs at the top of the slide. As you can see, both metrics have increased quarter over quarter and are in line with the respective third-quarter 2015 level.

This is due to production growth driving an increase in sales that outweighs the decrease in settlements on commodity derivatives year-over-year. I will point out that the adjusted cash flow and adjusted EBITDA shown here includes some of these third-party fees related to the acquisition of approximately $11 million.

Moving to slide 9 and an overview of our debt and liquidity positions. In the third quarter, we had several transactions related to our permanent financing of the acquisition. These include the issuance of approximately 9.1 million shares of equity for net proceeds of approximately $560 million, as well as $200 million of 1 1/8 convertible senior notes and $400 million of 6 1/8 senior notes.

Our borrowing base of $700 million was reaffirmed just last month and remains undrawn. As it currently stands, our commitment level has remained unchanged at $450 million, but will increase to the full $700 million upon the closing of the acquisition, which is expected in December.

Our current cash position is $1.2 billion, with an overall liquidity position of $1.6 billion. Pro forma for the expected closing, our third-quarter cash would be approximately $350 million with our overall liquidity position of around $1 billion.

Now, on to hedging. Our hedge summary on slide 10 includes the hedges in place as of September 30 plus new hedges entered into during October. We remain well-hedged for the balance of 2016 with approximately 50% of our oil volumes and nearly 60% of our expected gas volumes hedged for the fourth quarter of the year. As you can see, our oil is hedged well above the strip at just under $74 per barrel, with gas also on the money averaging $3.42 per Mcf.

Since our last update, we have added approximately 2 million barrels of 2017 oil hedges and 1 million barrels of 2018 oil hedges. Our 2017 and 2018 gas volume has remained unchanged.

Overall, it was another strong quarter. And we are very happy with the way things are shaping up for the full-year.

With that, I will turn the call over to Scott Reasoner for a look at our third-quarter operating results.

Thank you, Scott, and good morning, everyone. As both Bart and Scott mentioned, we were very pleased with the way our team executed in the third quarter. Production averaged over 65,000 barrels of oil equivalent per day, nearly a 40% increase over the third quarter last year. We turned in line 40 gross operated wells of which 8 were 2-mile laterals in the Wattenberg and were late in the quarter.

I'll touch on this more in a moment, but we are expecting the number of turn-in lines for the fourth quarter to be about half of this quarter. Also of note this quarter, we are dropping from 4 to 3 rigs -- or we dropped from 4 to 3 rigs, and plan to continue operating at this level into the first half of 2017.

On slide 13, you can see several highlights of our third quarter. Our commodity mix for the year continues to be in line with our expectations at 40% oil and approximately 60% liquids. Sequentially, our production increased 14% compared to the second quarter. For the full-year, and factoring in a small contribution from the expected closing of the Delaware acquisition in December, we are expecting to meet or slightly exceed the top of our production guidance of 22 million barrels of oil equivalent, and have a December exit rate of approximately 74,000 barrels of oil equivalent per day.

From an LOE standpoint, we had another tremendous quarter that came in at $2.33 per BOE. As winter sets in, we think this quarter probably serves as a low watermark and would expect LOE per BOE to come up a bit in the fourth quarter. However, as it stands, we expect our full-year LOE to be below our guidance range shown on the graph at the bottom of the page.

Next, on slide 14, we show a breakdown of our turn-in line and capital activity for the quarter. A couple of things I'd like to point out on this slide.

First, you can see the projected turn-in line count I was referencing earlier. Notice that the fourth quarter is substantially lower than the previous three quarters. This is primarily due to the scheduled release in a couple of weeks of the completion crew we are running, but also the fact that the wells are either MRL or XRLs. In fact, the nine MRL wells are already online with the 10 XRL wells currently being completed. Keep in mind the majority of these wells have a higher working interest than those in previous quarters, due to our recently completed acreage trade.

Second, note the capital -- projected capital for the full-year at the bottom of the page. As you can see, our full-year CapEx is still projected to be $400 million to $420 million. However, I'll note that this now includes the expected capital spend in the month of December for the Delaware. Previously, this was not included in our range and is more very-positive news from a CapEx perspective.

Slide 15 is an update of a slide we showed last quarter showing the details of our LDS and Sater projects, both of which continue to perform very well. For the LDS, all wells were performing in line with each other regardless of the pounds of sand per foot. And on the Sater, both the hybrid and slickwater jobs are performing about the same. Each of our completions through the end of the year are testing a combination of stage length, sand concentration and/or flow-back method.

Lastly, not shown on this slide, are the first eight XRL wells we turned in-line during the quarter. This pad is located on the east side of our acreage block, and production looks very encouraging to date, but is still in the flow-back process. Look for an update on this pad in the near future.

Moving on to slide 16, on the Utica, you can see there are a couple of updates here. In terms of capital, we now expect to spend $27 million from the year, down from $35 million previously. This is mainly due to reduced capital per well but also a little less expense related to lease renewals. Also, we have updated the performance chart to include both the Neff well and the Mason pad average.

As you can see, and as we mentioned last quarter, the Neff well was performing extremely well. To date, it is our highest performing well in the Utica, and on a per-1,000 foot basis, ranks among PDC's best wells regardless of the Basin. The Mason pad is a bit of a different story. Clearly, these wells are underperforming what we would like to see. As it stands, our plans with the Utica are to continue evaluating all of our producing wells, as well as the upcoming Miley pad, as we look to determine our 2017 budget and the future strategy in this Basin.

Moving to slide 17, we give a little more detail on the quarterly production and are adding a little flavor of some of the anticipated key 2017 themes, as we continue in our budget process. Notably, look for us to add a fourth rig in the Wattenberg sometime around midyear and to place an even greater emphasis on longer lateral drilling, primarily in and around the recently blocked up Middle Core position.

Obviously, we haven't finalized the budget, and the exact plans are subject to change due to commodity prices and a number of other reasons. But this provides a snapshot at where we are currently thinking.

With that, I will turn the call over to Lance for a brief overview of the Delaware Basin asset.

Well, thanks, Scott. And on slide 19, we provide a summary again of the transformational core Delaware basin acquisition that we announced to the market on August the 23rd, 2016. We are very pleased with the acquisition and we look forward to the expected closing date in December of this year.

This acquisition includes approximately 57,000 net acres with an average working interest of approximately 93% and nearly 100% operated. 41,000 net acres are located in Reeves County, Texas and 16,000 net acres located in Culberson County, Texas. Additionally, we acquired approximately 7,000 barrels of oil equivalent per day net production, while current production is approximately 7,500 barrels of oil equivalent per day net.

The initial purchase price was $1.5 billion, of which approximately $590 million in PDC equity will be issued to the seller at closing. In early September this year, we completed three capital market transactions, including $560 million net in PDC equity, $400 million of senior notes, and $200 million of converts. Upon closing, we expect that this acquisition will be funded with slightly over 75% equity.

Slide 20 provides an update of the well performance in the Eastern acreage block, where I'd like to highlight the early outperformance of the Aris-operated wells relative to PDC's acquisition type curves. In the upper left graph, you'll see that a 1 million barrel equivalent acquisition type curve in the Wolfcamp A interval is based upon 5,000 foot lateral.

Additionally, we plotted the actual production results from the three most recently completed Aris PDC wells normalized to 5,000 feet. After approximately 120 days, both the Keyhole and Sugarloaf wells are substantially exceeding the type curve. And the hanging H well, after almost 60 days, is also exceeding the type curve, and on the same trend as the Keyhole and Sugarloaf wells. We are very pleased with these results, recognizing that it's still early in the life of the wells.

The three recent Wolfcamp A wells had an average IP-30 of approximately 1,435 barrels of oil equivalent per day and average lateral length of about 4,100 feet. This equates to an average of about 350 barrels of oil equivalent per day per 1,000 foot of lateral. Additionally, the crude oil mix from the three Wolfcamp A wells have averaged approximately 60% thus far on a three-phase basis.

In the lower left graph, you'll see our 750,000 barrel acquisition type curve for the Wolfcamp B interval also based on a 5,000 foot lateral. Plotted relative to our type curve are the actual production results from the recently-completed Triangle well normalized to 5,000 feet. This well experienced completion issues and we estimate that only about 3,000 feet of the lateral was effectively stimulated.

After 60 days of production, the Triangle well is exceeding the type curve. The Triangle well had an IP-30 rate of about 725 barrels of oil equivalent per day from what we estimate to be the 3,000 feet of effective stimulated lateral. This would equate to an IP-30 rate of about 240 barrels of oil equivalent per day per 1,000 foot. The crude oil mix on this well is approximately 60% on the three-phase basis thus far.

Slide 21. This slide highlights the current projects that are being conducted within the Delaware Basin. PDC/Aris is currently operating two drilling rigs, one each in the Eastern and Central blocks. The rig in the Central block very recently drilled and cased the Liam well, our first operated two-miler. This well was drilled into the Wolfcamp B interval, and we plan to begin completion operations towards mid to late-November 2016.

The same drilling rig was moved north to drill a two-well pad on the Greenwich lease. These two wells have a targeted lateral length of approximately 7,500 feet, one of which is targeting the Wolfcamp B, and the other which will target the Wolfcamp A. Additionally, PDC/Aris is operating a second drilling rig in Block IV located in our Eastern leasehold area.

The first well, named the Argentine, is targeting the Wolfcamp A with an expected lateral length of about 4,500 feet. Our current midstream projects are focused on future infrastructure needs, and includes the installation of about 10 miles of steel gas gathering lines in the Central area, joining water supply well, and constructing two frac pits.

As previously stated, the projected capital spend for the Delaware Basin in the second half of 2016 is approximately $55 million to $65 million, of which about $10 million is projected from midstream capital. The majority of the projected $55 million to $65 million will be treated as a purchase price adjustment at the expected acquisition closing in December. Post-closing, we expect that $15 million to $20 million of the projected second-half capital will be included in our 2016 capital expenditures, as highlighted earlier by Scott Reasoner.

This final slide of our quarterly call highlights our initial key themes for our Delaware Basin assets in 2017, some of which may change as we finalize our 2017 capital programs. First of all, we expect to enter 2017 with two operated rigs and add a third rig sometime in the second half of 2017. We've identified several operating initiatives for 2017, most importantly, converting leasehold to HBP status.

Next, we are drilling two-milers in all three blocks, including the Western area. We also plan for multi-well pad drilling, as well as testing both the Wolfcamp A and B benches. We plan to expand our midstream assets in 2017 with the primary focus on well connections to our existing infrastructure.

Our midstream activities are expected to include drilling water disposal and water supply wells, plus installing additional water lines. Additionally, PDC will look for bolt-on leasehold additions and windward trades that block up contiguous acreage. Currently, our teams are working on multiple departmental integration plans, building out our organizational structure, and hiring additional staff in both Denver and in Texas.

In summary, we are very pleased with the Delaware Basin acquisition, and the great progress all of our teams have made towards a successful integration of the assets and staff, and to our organization. We also want to thank the Aires teams for their continued strong contributions on the Delaware Basin assets. We look forward to the expected December close and carrying the strong momentum into 2017.

And with that, I'll turn it over to the operator for Q&A.

(Operator Instructions) Welles Fitzpatrick, Johnson Rice.

Just for clarity, so we should think of the savings vis-a-vis keeping CapEx flat at $15 million to $20 million, is that right?

Yes, I think, Welles, when you look at our -- we haven't really revised our budget. We are really carrying over that same budget number (technical difficulty) into the current quarter with the idea that, really, we are going to spend in the Delaware in December what we are seeing as savings occurring in the rest of the operations. So, that $20 million feels pretty close to what I would say is a reasonable number.

Okay. Perfect. And then two more on the Delaware. You guys had talked about acquiring 3-D over the Grisham Fault. Is that in process? And is that any sort of barrier to drilling? Or not really an issue, given the de-risking other folks have done?

I think it's all part of our plan. And I don't -- first of all, we are not expecting to drill in and around there right away. That's something that we'll be doing over time. But yes, we, in fact, have identified the 3-D seismic that's available. It pretty well covers it. And I won't say 100%, but it's pretty good coverage over that area and the other areas, not just that area.

So we are likely going to own that 3-D seismic about the time we close on this deal, and we'll start using it in-house at that point. We do have access to much of what's available already through Aires, and obviously those licenses will have to be acquired by PDC. But really looking to use that as a tool, not just across the Grisham Fault but across the entire acreage position.

That's super. And then just one last one, if I could, if you guys have any update on the Raise The Bar initiatives, and how those might be looking going into the vote here?

Yes, obviously, we need to get to next Tuesday, Welles. But right now we've been very involved in the campaign around Raise The Bar. And the best I can say is, things look slightly favorable in that initiative right now. So, I would say we are encouraged, but again, we've got to get to next Tuesday.

Well, that's great. Knock on wood and congrats on the quarter. Thanks.

(Operator Instructions) Mike Scialla, Stifel.

I realize you don't have a formal plan out there yet, but just thinking about some of the requirements you have for saving acreage in the Delaware, and given the uncertainty in oil prices right now, how much flexibility is there in that plan?

And I guess my thought is that everything is held by production in the Wattenberg. Would that be where you would potentially ramp down if needed, if commodity prices don't cooperate?

Yes, let me start on the second part of capital allocation, and Mike -- yes, and I'll let Scott jump on what's required to kind of cover our HBP status in the Delaware. But if we were to slow down -- say, oil drops into the low 30s, and that was our outlook -- and I think it's really important, that would have to be our outlook long-term -- we would use the Wattenberg as our flex capital point.

You know, our capital budget right now, again, nothing has been approved; in line with what Lance presented in the rollout, we obviously, heading into next year, are going to have more intense capital going into the Wattenberg than the Delaware on a total basis. So the Wattenberg would definitely be where we would slow down if we need to back off on our capital spend.

And why don't you cover what it takes to hold the acreage?

Yes. And Mike, I think when we look at this overall, we're talking about those two rigs, and we really need to run those rigs pretty consistently in order to hold the acreage. Feel like we can do that, like Bart said, well down into the $30 per barrel range of pricing. It also comes down to the idea that, at this point, we're still contemplating adding a rig in each area. We probably don't need to add the third rig to hold the acreage in that area.

And we obviously, as Bart described, would not add a fourth rig in Wattenberg if prices were projected to be low for a long period of time. But it's very flexible in Wattenberg. It's much more -- I would say much more of a requirement in Delaware that we run at least the two rigs.

Great, thanks. And then, Scott, I had a question for you. I may have misheard you in your prepared remarks, but you talked about the performance you've been burying the sand concentration in a lot of the Wattenberg wells. It sounded like, if I heard you correctly, that you are not seeing any difference in terms of the performance right now? Is that right? Or could you clarify that for me?

You're correct, Mike. You can see on the graph, we really don't see a lot of difference between the two sand concentrations that we have on that LDS pad. It doesn't mean that's an absolute answer yet, but we are definitely more focused on the other parts of the testing that we did there because of that, which puts us more pointed toward the shorter stage lengths, and dealing with our flow back -- our different flow back method, both of which we think contributed fairly significantly to that uplift.

That's what we are really testing through the end of the year on the various projects we have, are that variation of sands concentration -- or I mean, stage length and flow-back method. But we're also still running some tests at the 1,300 pounds-per-foot type range. We're not planning to go up to those upper numbers through the rest of this year, but probably will reconsider that.

I know some of our peers out there in the Wattenberg, and obviously down in the Delaware, we're seeing the same thing, are increasing sand concentrations. But we are looking at the data. And at this point, it's not encouraging us. It's also the more expensive part of the additional costs associated with these tests we are running. So, keeping all that in mind, that's where we are headed for now.

Any thought as to where you are in the play? I guess I've heard that the higher sand concentrations may have a more favorable impact where the GOR is a little bit lower, although it looks like that LDS pad is located in not the highest GOR part of the play. So -- but any thoughts around that?

Yes, I think when you look at this, we're going to -- first of all, we are going to be focusing most of our drilling in that blocked-up acreage that we have after the acreage trade. So the test for us that we are seeing on the LDS, LDS is very significant on how we see things going forward.

As we move into the more oily areas, we could see this change and need a little more sand concentration that near wellbore permeability, if you -- the induced permeability. So I think that's a possibility, but we really aren't there and probably won't be out in that area much, if at all, this next year. So it may not impact us as much as it might others.

Got it, thanks.

Jeff Robertson, Barclays.

Lance, question on the Wolfcamp A completions that you all highlighted performing above the type curve. Is there a difference in how those wells were completed versus what was used to develop the 1 million BOE type curve?

I think the answer is yes. Many -- what we are really dealing with in terms of the type curve is many of the older completions still. And these recent completions were conducted by Aris. But what you see there is a 2,000 pounds-per-foot of sand, 100 feet between stages, and we really see that changing the productivity.

But also their flow-back method -- and I say their; it's really Aris's, soon to be ours -- approach to this has been similar to what we're -- the way we are approaching things in the Wattenberg. It makes good sense to us that the productivity is up. We obviously are continuing to see that confirmation.

And we will continue to approach our completion process with a similar approach early in the life of these -- in the life of our taking over this operation. So I think we're -- we believe it's making a big difference, and you see it in those early wells. They're phenomenal; they're phenomenal performing wells at this point. And we are excited about getting more of those going.

Scott, how do you expect the oil cut to vary over the life of these wells? Or do you have enough information to know yet?

You know, Jeff, that's one of the things that we are going to be monitoring over time. I mean, thus far, three-phase basis, as we talked about, is around 60% crude oil. So we are very encouraged by that. And it's in the range that we outlined as far as the oil mix with the rollout.

In this Eastern area, we were anticipating between 50% and 70% crude oil, so it's right in the range of that. So, there could be some variances a bit over time. But where we sit today, and thus far with the data that we have after the 120 days, we are right down the fairway of that range.

Thank you very much.

Sure.

Steve Berman, Canaccord.

Just following up on Jeff's question on those three Wolfcamp A wells, can you discuss what the cost of those wells were, and how that lines up to your expectations? And can you -- do you see yourself being able to bring those costs down once you take over operations?

I think at this point, I can't speak specifically to how those wells came in on their nickel over there at Aris. I will say that we've used their data to gather our estimates of those costs. So I would believe they are probably close to that $6.5 million kind of range that we've put out for a 1 mile lateral.

I think it's a little bit early for us to project where we can go. But even within the -- in terms of cost -- but even within what we've shown, we feel like we can drop several-hundred-thousand-dollars off per well just by going to multi-well pads. And I still think there's room for improvement on getting a rig running consistently, and getting the efficiency associated with that as a part of the equation.

And then on the completion side, I think when you drill a single well -- and everybody pretty well understands this -- but when you look at that, you don't get any efficiency on a completion, particularly when you are doing a plug and perf operation, it's very inefficient on single wells. So, we've got a lot of room to move.

I think we've seen those improvements on the Wattenberg side. And I think we'll get there, but it's going to take some time into next year for sure, because we are really looking like we've talked about at drilling single-well batteries.

All right, just a follow-up. Remind us, what's the estimated cost for a two-mile lateral here?

Yes, we've got about $9.5 million in, and that's on a single well. When you look at the two-mile multi-wells, we think we'll get down around $9 million. And again, that's real early, so I hope everybody recognizes we've got a lot to learn on that.

We are very pleased. We've got the first well drilled out of the shoots with the Aris team. They did a great job executing on a two-mile lateral. And we're going to start completing that in a couple of weeks here. But to do that first one is always a little bit nervous for me, and I'm really excited we got it done, and feel like we can do more of them because of that.

Great. All right, that's it. Thank you.

There are no further questions. I'd like to turn the call over to Bart Brookman, CEO, for any closing remarks.

No -- thank you, Michele, and thank you, everyone, for joining the call. We, as always, appreciate your ongoing support in the Company.

Ladies and gentlemen, thank you for participating in today's conference. That does conclude the program and you may all disconnect. Everyone have a great day.