Nov 3, 2016
Executives
Michael G. Edwards - PDC Energy, Inc.
Barton R. Brookman - PDC Energy, Inc.
R. Scott Meyers - PDC Energy, Inc.
Scott J. Reasoner - PDC Energy, Inc.
Lance A. Lauck - PDC Energy, Inc.
Analysts
Welles W. Fitzpatrick - Johnson Rice & Co.
LLC Michael Scialla - Stifel, Nicolaus & Co., Inc. Jeffrey Robertson - Barclays Capital, Inc.
Stephen Fred Berman - Canaccord Genuity, Inc.
Operator
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 the question-and-answer session and instructions will be given at that time. 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.
Michael G. Edwards - PDC Energy, Inc.
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 two of that presentation.
We will present some non-U.S. 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-U.S.
GAAP financial measures. With that, let's get started, and I'll turn the call over to Bart Brookman, our CEO.
Bart?
Barton R. Brookman - PDC Energy, Inc.
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 in 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 cost came in at $2.33 for 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 details 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 at just over 2, and exit 2017 with a debt to EBITDA at 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 in 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 mid-year 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 our financial overview.
R. Scott Meyers - PDC Energy, Inc.
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 of 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 320 or 27% in that same time. Included in our net loss for the quarter are several one-time non-recurring expenses related to our Delaware Basin acquisition.
Core 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 eight, 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 include some of these third-party fees related to the acquisition of approximately $11 million.
Moving to slide nine 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 included the issuance of approximately 9.1 million shares of equity for net proceeds of approximately $560 million, as well as $200 million of 1.125% convertible senior notes and $400 million of 6.125% 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 around $1 billion. Now on to hedging.
Our hedge summary on slide ten 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 output 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 in 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'll turn the call over to Scott Reasoner for a look at our third quarter operating results.
Scott J. Reasoner - PDC Energy, Inc.
Thank you, Scott, and good morning, everyone. As both Bart and Scott mentioned, we are very pleased with how 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 eight were two 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 four to three rigs, or we dropped from four to three 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 have another tremendous quarter that came in at $2.33 per Boe. As winter sets in, we think this quarter probably serves as a low water mark 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 turned-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 turned-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're 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 the 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 slick water 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 for 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 is 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 under performing what we'd 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 a 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're currently thinking. With that I'll turn the call over to Lance for a brief overview of the Delaware Basin asset.
Lance A. Lauck - PDC Energy, Inc.
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're 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.
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-out performance of the Arris-operated wells relative to PDC's acquisition type curves.
In the upper left graph, you'll see that our one-million-barrel equivalent acquisition type curve in the Wolfcamp A interval is based upon a 5,000-foot lateral. Additionally, we plotted the actual production results from the three most recently completed Arris PDC wells normalized to 3,000 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 IP30 of approximately 1,435 barrels of oil equivalent per day, an 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 IP30 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 IP30 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 a three-phase basis thus far.
Slide 21. This slide highlights the current projects that are being conducted within the Delaware Basin.
PDC Arris 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 Arris is operating a second drilling rig in Block 4, 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 ten miles of steel gas gathering lines in the central area, drilling a 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 for 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 lease hold 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 a 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 lease hold additions and win-win 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 the successful integration of the assets and staff into our organization.
We also want to thank the Arris 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
Our first question comes from Welles Fitzpatrick of Johnson Rice. Your line is open.
Welles W. Fitzpatrick - Johnson Rice & Co. LLC
Hey, guys. Good morning.
Michael G. Edwards - PDC Energy, Inc.
Hey, Welles.
Scott J. Reasoner - PDC Energy, Inc.
Hi, Welles.
Welles W. Fitzpatrick - Johnson Rice & Co. LLC
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?
Lance A. Lauck - PDC Energy, Inc.
Yeah. I think, Welles, when you look at our, we haven't really revised our budget.
We're really carrying over that same budget number in to the current quarter with the idea that really we're going to spend in the Delaware in December what we're seeing as savings occurring in the rest of the operation. So that $20 million feels pretty close to what I would say is a reasonable number.
Welles W. Fitzpatrick - Johnson Rice & Co. LLC
Okay. Perfect.
And then two more on the Delaware. You guys had talked about acquiring 3D 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?
Lance A. Lauck - PDC Energy, Inc.
I think it's all part of our plan and, first of all, we're not expecting to drill in and around there right away. That's something that we'll be doing over time which, as we, in fact, have identified the 3D seismic.
It'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. But we're likely going to own that 3D 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 Arris and, obviously, those licenses will have to be acquired by PDC. But really looking at that as a tool, not just across the Grisham fault but across the entire acreage position.
Welles W. Fitzpatrick - Johnson Rice & Co. LLC
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 boat here.
Barton R. Brookman - PDC Energy, Inc.
Yeah, obviously, we need to get to next Tuesday, Welles. But right now, we've been very involved in the campaign around Raise the Bar.
The best I can say is things look slightly favorable in that initiative right now. So I would say we're encouraged but, again, we've got to get to next Tuesday.
Welles W. Fitzpatrick - Johnson Rice & Co. LLC
Well, that's great. Knock on wood and congrats on the quarter.
Thanks.
Operator
Our next question comes from Mike Scialla of Stifel. Your line is open.
Michael Scialla - Stifel, Nicolaus & Co., Inc.
Yes. Hi, guys.
Barton R. Brookman - PDC Energy, Inc.
Good morning, Mike.
Scott J. Reasoner - PDC Energy, Inc.
Good morning.
Michael Scialla - Stifel, Nicolaus & Co., Inc.
Realized 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's held by production in the Wattenberg.
Would that be where you would potentially ramp down if needed, if commodity prices don't cooperate?
Barton R. Brookman - PDC Energy, Inc.
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 $30's, and that was our outlook.
I think it is really important, that would have to be our outlook long term. We would use the Wattenberg as our flex capital point.
Our capital budget right now, again nothing's been approved, in line with what Lance presented in the rollout, we obviously, heading into next year, are going to have more intense capital 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 once you cover what it takes to hold the acreage.
Scott J. Reasoner - PDC Energy, Inc.
Yeah 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. I 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.
Michael Scialla - Stifel, Nicolaus & Co., Inc.
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 varying the sand concentration in a lot of the Wattenberg wells.
It sounded like, if I heard you correctly, that you're not seeing any difference in terms of the performance right now? Is that right, or could you clarify that for me?
Scott J. Reasoner - PDC Energy, Inc.
You are 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're 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 different flowback method, both of which we think contributed fairly significantly to that uplift. That's what we're really testing through the end of the year on the various projects we have are that variation of stage length and flowback 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, increasing sand concentrations, but we're 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're running. So keeping all that in mind that's where we're headed for now.
Michael Scialla - Stifel, Nicolaus & Co., Inc.
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 located in, not the highest GOR part of the play.
So, but any thoughts around that?
Scott J. Reasoner - PDC Energy, Inc.
Yeah. I think when you look at this – first of all, we're 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're 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 well bore propped permeability, 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.
Michael Scialla - Stifel, Nicolaus & Co., Inc.
Got it. Thanks.
Operator
Our next question comes from Jeff Robertson of Barclays. Your line is open.
Jeffrey Robertson - Barclays Capital, Inc.
Thanks. Lance, a 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 million Boe type curve?
Lance A. Lauck - PDC Energy, Inc.
And I think the answer is yes. In many – what we're really dealing with in terms of the type curve is many of the older completions still and these recent completions were conducted by Arris.
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 flowback method, and I say their; it's really Arris' soon to be ours, approach to this has been similar to the way we're 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 believe it's making a big difference and you see it in those early wells. They're phenomenal performing wells at this point and we're excited about getting more of those going.
Jeffrey Robertson - Barclays Capital, Inc.
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?
36:35 : Jeff, that's one of the things that we're going to be monitoring over time. I mean thus far, three-phase basis as we talked about is around 60% crude oil.
We are very encouraged by that, and it's in the range that we outlined as far as the oil mix with the roll-out. 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 overtime, but where we sit today and thus far with the data that we have after the 120 days, we're right down the fairway of that range.
Jeffrey Robertson - Barclays Capital, Inc.
Thank you very much.
Scott J. Reasoner - PDC Energy, Inc.
Sure.
Operator
Our next question comes from Steve Berman of Canaccord. Your line is open.
Stephen Fred Berman - Canaccord Genuity, Inc.
Thanks. 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 binds up to your expectations? And can you see yourself being able to bring those costs down once you take over operations?
37:45 : I think at this point I can't speak specifically to how those wells came in on their nickel over there at Arris. I will say, but we've used their data to gather our estimates of those costs.
So I would believe they're probably close to that $6.5 million kind of range that we put out for a one mile lateral. I think it's a little bit early for us to project where we can go, but even within – in terms of cost, but even within what we've shown, we feel like we can drop several hundred thousand dollars off a 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're doing a plug-in perf operation.
It's very inefficient on single wells. So we've got a lot of room to move and 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're really looking like we've talked about it drilling single well batteries.
Stephen Fred Berman - Canaccord Genuity, Inc.
All right. Just a follow-up.
Remind us what's the estimated cost for a two-mile lateral here?
Lance A. Lauck - PDC Energy, Inc.
Yeah. We've got about $9.5 million 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 really early.
I hope everybody recognizes we've got a lot to learn on that. We're very pleased we got the first well drilled out of the chutes with the Arris 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 you know 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.
Stephen Fred Berman - Canaccord Genuity, Inc.
Great. That's it.
Thank you.
Operator
There are no further questions. I'd like to turn the call over to Bart Brookman, CEO, for any closing remarks.
Barton R. Brookman - PDC Energy, Inc.
Oh, thank you, Michelle, and thank you, everyone, for joining the call. We, as always, appreciate your ongoing support in the company.
Operator
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.