Feb 28, 2017
Executives
Michael G. Edwards - PDC Energy, Inc.
Barton R. Brookman - PDC Energy, Inc.
Scott J. Reasoner - PDC Energy, Inc.
David W. Honeyfield - PDC Energy, Inc.
Lance A. Lauck - PDC Energy, Inc.
Analysts
Stephen Fred Berman - Canaccord Genuity, Inc. Welles W.
Fitzpatrick - Johnson Rice & Co. LLC Michael A.
Glick - JPMorgan Securities LLC David A. Deckelbaum - KeyBanc Capital Markets, Inc.
John Nelson - Goldman Sachs & Co. Neal D.
Dingmann - SunTrust Robinson Humphrey, Inc. Daniel Eugene McSpirit - BMO Capital Markets (United States) David R.
Tameron - Wells Fargo Securities LLC Kyle Rhodes - RBC Capital Markets LLC Jeffrey L. Campbell - Tuohy Brothers Investment Research, Inc.
Operator
Good day, ladies and gentlemen, and welcome to the PDC Energy Fourth Quarter 2016 Conference Call. As a reminder, today's conference is being recorded.
I would now like to introduce your host for this conference call, Mr. Mike Edwards, Senior Director of Investor Relations.
Please go ahead, sir.
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, Chief Operating Officer; and David Honeyfield, Senior Vice President and CFO.
We 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 the forward-looking statements on slide 2 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. First, I'd like to welcome David Honeyfield to the call.
This is David's first call of many as PDC's CFO. We're extremely excited to have him as part of our team.
Now, 2016, truly an eventful year for the company and transformational in many ways. We entered 2017 stronger than ever with some incredible opportunities as we pursue our reliable growth from the Wattenberg and begin the journey of unlocking what we see as incredible value in our newly acquired Delaware assets.
Let me hit some highlights from 2016. Obviously, the Delaware transaction, the quality of the acreage we acquired now at 62,500 acres in the capital market transactions in September and the positive support we received from our investors.
Next, annual production levels for the year were 22.2 million barrels of oil equivalent; that was a 44% improvement over 2015 levels. We recently announced our year-end 2016 proved reserves at 341 million barrels equivalent.
We were extremely pleased with these numbers as it represented a 25% increase from 2015 levels and a 409% reserve replacement level. Last year, the cost structure of the company also continued to improve.
$2.70 per Boe lifting cost that is down from $3.71 per Boe in 2015, a 27% reduction. This coupled with reduced de-DUCs in the Wattenberg were instrumental in helping maintain margins on our production.
And then our EH&S statistics continue to improve, a combined effort of our operational and environmental health and safety teams. And then from a financial perspective, we ended the year with a very strong balance sheet: debt-to-EBITDA (sic) [EBITDAX] of 2.1 times, over $240 million cash on hand, and over $900 million of liquidity; plenty of financial flexibility for the company to execute on our capital programs.
And then our 2016 capital spend levels came in at $400 million, a great number at the low-end of our guidance. Now, let me update everyone where we are headed in 2017.
Last December, we released our plans to spend between $725 million and $775 million on our capital budget and produce between 30 million and 33 million barrels of oil equivalent, approximately a 40% growth for the company. This included drilling 28 wells in the Delaware, 145 wells in the Wattenberg, and 2 wells in our Utica project.
So where do we stand today? We're pleased with our production levels and our guidance remains 30 million to 33 million barrels of oil equivalent, and we anticipate that our 2017 exit rate should approach 100,000 Boe per day.
On the drilling side, our operating team at Delaware recently had access to an ideally designed rig for that basin. We elected to contract this rig effective last week, which we expect will increase our turn-in-line well count in the Delaware from 19 to 26 wells in 2017.
This decision will also help accelerate the pursuit of HBP status on our Delaware land position. We now anticipate our capital spend will be at or near the high-end of our guidance range, or $775 million, primarily due to the early deployment of this rig, along with some cost increases in the Delaware, particularly on the completion side.
Again, we plan on executing this capital program while strengthening the balance sheet through 2017, with year-end debt-to-EBITDA (sic) [EBITDAX] expected to be 1.7 times. And last, in 2017, expecting two new technical enhancements in both Wattenberg and Delaware.
We are very encouraged by these initiatives, and we believe they will enhance productivity of our projects and enhance the capital efficiency of our capital budget. Scott Reasoner will cover some of these initiatives in a lot more detail in a moment.
So, in closing, I would like to thank all of the PDC employees for their efforts in 2016; truly a transformational year for the company with our operational performance and our launch into the Delaware Basin. This enabled PDC to enter 2017, again, stronger than ever.
With that, I'd like to turn the call over to Scott for an update on our operations.
Scott J. Reasoner - PDC Energy, Inc.
Thanks, Bart, and good morning, everyone. The fourth quarter was very strong from a production standpoint and included a lot of work in closing our Delaware Basin acquisition, integrating the assets and organization, and beginning our operational execution phase.
As you can see here, production for the quarter was just under 70,000 Boe per day and included the production of about 175,000 barrels of oil equivalent in December, and that was from the Delaware closing. As a reminder, back in August when we announced the acquisition, the asset was producing approximately 7,000 barrels of oil equivalent per day.
Due to the timing of turn-in-lines and midstream facility upgrades, December production averaged approximately 5,700 barrels of oil equivalent per day net. I will add that with recent turn-in-lines and the completion of some facility upgrades, production in the Delaware is currently back above 6,500 Boe per day.
This production is expected to continue growing as we have a fulltime frac crew running and generating consistent turn-in-lines. For the first quarter, we anticipate a similar corporate production rate as the fourth quarter with the majority of our turn-in-lines scheduled later in the quarter.
Slide 8 gives a bit more color on quarterly production and LOE. We turned-in-line 22 gross wells in the quarter, including our first PDC-operated Delaware Basin well, the Argentine.
Oil volumes tracked above our expectations and we had a comparatively larger outperformance in gas, resulting in our production commodity mix being 39% oil and 39% natural gas with the balance in NGLs. This was true for both the quarter and full year.
Lastly, our full-year lifting costs were a very impressive $2.70 per Boe which was a 27% decrease from the prior year. David will provide a little color on 2017 expectations in a few minutes.
A couple of things to go over on slide 9; first, our fourth quarter 2016 capital investment level was $78 million. This reduction in expected capital was driven by efficiencies we realized in the Wattenberg.
In terms of 2017, we've made some adjustments to our capital plan in order to further focus our priorities and to reflect some service cost adjustments. We are now targeting at or near the high-end of our $725 million to $775 million capital range.
There are a couple moving parts that partially offset each other in order to stay within the range. First, in the Delaware, our third rig is operational and we'll ensure we stay ahead of our HBP program.
This was originally planned for early in the fourth quarter. We also increased our service cost expectations by 10% in the Delaware to account for some upward pressure we've been seeing.
Next, offsetting some of the increased investment, we plan to defer our planned activity in the Utica for the year as we evaluate our strategic options. Finally, in the Wattenberg, we have adjusted our drilling and completion schedule a bit in the back end of the year.
We are comfortable with our D&C costs as we've yet to see the same magnitude of cost pressure and have a little wiggle room due to our efficiency gains. All in all, we plan to have more turn-in-lines in the Delaware almost equally offset by the reduced number in the Wattenberg and in the Utica.
We still expect to grow production by approximately 40% and produce between 30 million barrels of oil equivalent and 33 million barrels of oil equivalent for the year. Given that the timing of the added turn-in-lines for the year are quite late in 2017, we believe that these adjustments will set us up extremely well going into 2018.
Moving to some updated well results in the Wattenberg on slide 10, we're highlighting our strong early results from our tighter stage spacing tests. All four of these pads were completed with stage spacing of approximately 170 feet compared to approximately 200 feet for the majority of our 2016 Wattenberg wells.
First of all, the LDS and Cockroft pad shown on the top two charts continue to outperform their MRL 685,000 barrel of oil equivalent type curve by 30%-plus. This slide also shows our two latest XRL pads, the Connie and Bihain, shown on the bottom two charts.
We are only a couple of months into production on these two pads. But to-date, they are outperforming our 850,000 barrel of oil equivalent type curve by more than 30%.
In 2017, the majority of our drilling program will be focused on the highlighted acreage block shown in the center of the slide and all of our completions from this point forward will be done with 170 feet or less stage spacing as we continue to push for improvement. Moving to slide 11.
We have some early results in the Delaware. Here, we have a look at our Eastern acreage, Wolfcamp A wells as well as our updated projected D&C costs.
First of all, we've updated production from our previously disclosed wells, the Sugarloaf, Keyhole, and Hanging H wells. And they all three continue to significantly outperform our 1 million barrel of oil equivalent type curve.
Additionally, we've added our first 100% operated well in the basin, the Argentine. As you can see, production from the Argentine is also tracking well above our 1 million barrel oil equivalent type curve and is averaging approximately 70% oil.
We're obviously very encouraged by these results. It is important to note that similar to the Wattenberg, we are utilizing choke management on our first operated well.
In fact, the Argentine was choked back more aggressively than the other wells shown here. Lastly, on the bottom right, you can see our originally budgeted single well cost from December and the updated figures that represent an approximate 10% increase in costs.
Moving to slide 12. You can see we've outlined a couple of key operational takeaways for 2017.
In the Wattenberg, look for us to run several stage spacing tests below what we've shown today, but generally speaking, we've been seeing very positive results with both tighter spacing and our choke management program. Look for us to continue on both of these fronts this year.
In the Delaware, we're very encouraged with early results we're seeing, and as we discuss, now plan to be operating three rigs in the basin from this point forward. We also plan on increasing our midstream infrastructure footprint in the Delaware and will provide more detail on our longer-term vision for these assets at Analyst Day.
2016 was a tremendous year for PDC from an operating standpoint. I'd really like to thank our teams that executed on every phase of our operation and kept this machine running so smoothly.
2017 is sure to be a year with a new set of challenges and I am confident in the people in place to meet them head on. With that, I'll turn the call over to David for a financial review.
David?
David W. Honeyfield - PDC Energy, Inc.
Thanks, Scott, and good morning to all those on the call. Let me just start by saying how fortunate I feel to be part of PDC.
As folks on the call probably already know, the PDC team is a group of talented and passionate professionals, and we have a great set of assets to drive value for all those involved. I'm looking forward to sharing my experience and contributing to the future success of the company.
Looking at slide 4 (sic) [14], let's take a look at our GAAP metrics for the fourth quarter and the full year of 2016 and 2015. The comparative fourth quarter production results were 34% higher in 2016, coming in at 6.4 million Boe, bringing our total production for the year to 22.2 million barrels of oil equivalent.
With the increase in our production and an improvement in the commodity pricing environment, we saw a 64% increase in our 4Q sales revenue versus the fourth quarter of 2015. Our all-in corporate oil differential, including transportation, gathering, and processing, for the full year came in at $4.88 per barrel.
Our 2016 result is favorable by almost $5 per barrel when compared to the same full-year average in 2015. This reduction in the all-in differential was primarily driven by our marketing team's success in securing improved oil sales contracts continually throughout 2016.
Keep in mind that the average NYMEX price for crude oil was $5.48 lower in 2016 than in 2015. So when you combine the offset from our improvement in the de-DUCs, our resulting all-in net realized value per barrel was effectively unchanged from year to year.
The company's production costs for the full year 2016 were $110 million or $4.95 per Boe. This represents an 11% improvement on a per-Boe basis for the full year 2015.
Our quarterly production costs were $5.23 per Boe, up slightly from the same period in 2015 due primarily to an increase in production taxes driven by higher commodity prices. The 2016 G&A shown here includes just over $12 million of fees related to our Delaware Basin acquisitions.
Excluding these fees, our G&A per Boe for the full year 2016 was $4.52, a 27% decrease compared to 2015. I'll add more on this in a minute as we expect to continue to see the downward trend in our G&A cost per Boe moving through 2017.
I do want to remind folks that at the end of the year, we had 65.7 million shares of common stock outstanding. This number includes the equity issuances earlier in the year and the closing of the Delaware transaction in early December.
On a GAAP basis, we recorded a loss of $5.01 per share for the full year, which includes DD&A and the impairment charges taken earlier in the year. Last item on this slide is that the net cash flow from operations for the full year, which came in at $486 million, nearly 18% higher than in 2015.
Moving on to our non-GAAP metrics shown on slide 15, you can see on the graphs at the top of the page the impressive quarterly growth delivered from both adjusted EBITDA and adjusted cash flow from operations. Adjusted cash flow from operations increased 11% in 2016 to $467 million, and for the fourth quarter, was $141 million which was 10% higher than the same quarter the year prior.
Similarly, adjusted EBITDA for 2016, which includes the add-back of the $44 million note allowance that was recognized in the first quarter, increased 8% to $480 million compared to the $443 million a year ago. The clear driver to the improvements in each of these metrics is our continued ability to deliver value-driven production growth in spite of the commodity price environment we've experienced over the last two years.
Moving to slide 16, here, we provide an overview of our debt maturity schedule, as well as a snapshot of our leverage and liquidity at year-end. I'm sure people recall that 2016 was a busy year for the company in the capital markets and that we settled the convert issue that was due in 2016.
We issued a new convertible note that has a 1.125% coupon. We issued $400 million in senior notes priced at 6.125%.
And we elected the full $700 million commitment under our revolving credit facility. The culmination of this activity, the capital investments in 2016, and the closing of the Delaware acquisitions resulted in our year-end liquidity position of approximately $930 million.
And our debt-to-EBITDAX ratio, as defined by our revolving credit facility agreement, was 2.1 times at year-end and we expect this metric to improve throughout 2017 with top-line EBITDA growth. Turning to the next slide, let's quickly touch on our hedge position.
We benefited materially from our hedge settlements in 2016 as we utilized our hedges as a risk management strategy. Our hedges for 2017 and 2018 are at prices that are much closer to the current commodity strip as we've rolled hedges off through normal settlements as well as placing new hedges using both swaps and collars based on the market conditions at the time.
For 2017, you can see that we currently have approximately 9.5 million barrels of crude hedged, which is approximately 70% of our expected midpoint 2017 production volume. These barrels are hedged at a weighted average price of approximately $50 per barrel when you consider the swaps and the floor prices of the collars.
Our 2017 gas hedge position is just over 38 million MMBtu which represents approximately 60% of our expected volumes. These are at a weighted average NYMEX settlement price of $3.51 per MMBtu.
Just to emphasize, this is a NYMEX settlement price, which is a little bit different than how we presented this previously. We do have basis swaps in place as well covering a portion of our production and those are footnoted on the slide.
Our 2018 positions are also shown on the slide. Look for us to continue to monitor the markets and opportunistically layer in additional positions and incremental wedges to help insulate the strong internal rates of return from our capital investment program.
Transitioning now from 2016 to 2017, I'd like to make a couple of comments about our 2017 financial guidance ranges. Bart and Scott have already touched on the production range of 30 million Boe to 33 million Boe and our expectations that we'll be near the top-end of our capital investment range of $775 million.
So here we're providing indications related to other key inputs. LOE for the year is expected to be right around $3 per Boe, this is a slight increase compared to 2016 due mainly to the associated higher lifting costs in the Delaware Basin.
Keep in mind that the Wattenberg is going to be the primary contributor to production here in 2017. Moving to G&A, we anticipate a level of $3.25 to $3.60 per Boe.
This includes the integration of the Delaware team and considers our production growth, yielding further efficiencies for this metric during the year. Our transportation, processing, and gathering shows a modest increase from 2016 on a per Boe basis.
This is largely a result of our ability to pipe more oil out of the Wattenberg Field on Saddle Butte crude oil gathering system. We continue to pursue the strategy of oil piping arrangements out of the Wattenberg as it serves to reduce truck traffic in the field.
Lastly, we're providing realization factors for our crude, natural gas, and NGLs. These realization factors do not include the effect of the $0.90 per Boe of transportation, gathering, and processing shown on the chart on the lower right that those costs are recorded separately in our results of operations.
So hopefully, this information is helpful to those on the call in terms of understanding the drivers for our performance in 2016 and help provide a clear picture of our plans for 2017. With that, we'll now turn the call back to the operator for Q&A.
Operator
Our first question comes from Steve Berman with Canaccord.
Stephen Fred Berman - Canaccord Genuity, Inc.
Thanks. Good morning, everyone.
Looking at slide 11, Bart or Scott, the price – the inflation in the Delaware Basin, what's mostly driving that, and are you looking to maybe lock in costs so that 10% doesn't get any worse? Can you elaborate on that a bit?
Scott J. Reasoner - PDC Energy, Inc.
Yeah. This is Scott.
And I can give you a little flavor. We've seen, as many of our peers have seen, upward pressure, and it's definitely focused toward the completion side but also on the drilling side.
We've seen some uplift there as well. It's something that is in terms of trying to lock that in, most of the suppliers look at you and say, you know what, we're seeing upward pressure at this point.
They really aren't willing to lock it in very easily. And I also think that if you lock it in at a substandard level and expect the same services, somebody that's paying more, that's a difficult circumstance to put our suppliers in.
So we really look at that as something that we generally look at it and say, we'd like to pay under market is just a little bit, but stay connected overall, because the service goes away if your costs get too low relative to the other folks that are paying out there.
Stephen Fred Berman - Canaccord Genuity, Inc.
Got it. And then, moving up to the Wattenberg, how do you see the mix in 2017 between MRL and XRL turn-in-lines?
Thanks.
Scott J. Reasoner - PDC Energy, Inc.
Yeah. Really see that distributed about, and I'm going to give you percentages that are good approximations, these are – there's still a little bit of movement in these numbers as we go through the year, but about 35% SRLs, 25% MRLs, and 40% XRLs is a good rough estimate.
Stephen Fred Berman - Canaccord Genuity, Inc.
Perfect. All right.
Barton R. Brookman - PDC Energy, Inc.
And, Steve, I do believe the XRLs we've got are weighting towards the second half of the year, if I remember correctly.
Stephen Fred Berman - Canaccord Genuity, Inc.
Perfect. All right, thanks, Bart.
Thanks, Scott.
Scott J. Reasoner - PDC Energy, Inc.
You bet.
Operator
Our next question comes from Welles Fitzpatrick with Johnson Rice.
Welles W. Fitzpatrick - Johnson Rice & Co. LLC
Hey. Good morning.
Barton R. Brookman - PDC Energy, Inc.
Good morning, Welles.
Welles W. Fitzpatrick - Johnson Rice & Co. LLC
Jump to the Delaware, if we could just talk about the midstream side for a little bit. That 100% owned and op system that you all have, are the third-party volumes on that, is that mainly just royalty owners or do you have other competitors going through that system?
Lance A. Lauck - PDC Energy, Inc.
Sure, Welles. This is Lance.
So on the midstream side in the Delaware Basin, the volumes we currently have going through it are primarily equity volumes we have from our company. Obviously, part of the volumes going through that are the royalty volumes as well.
So, I mean, one of the things we think about as we continue to grow and expand the midstream system here is the opportunities to bring on additional third-party volumes into our system. So, that's something that we're very much focused on and think about going forward.
But that's sort of what we sit today on, Welles.
Welles W. Fitzpatrick - Johnson Rice & Co. LLC
Okay. Perfect.
And then another in the same area. I think as we're looking at picking up some 3D over the Grisham Fault, have you done that yet and has it shown you anything that might shift your understanding of how that plays out?
Scott J. Reasoner - PDC Energy, Inc.
We did acquire 3D seismic to cover really most of our play out there and not just that area around the Grisham Fault. And does it really change our perspective?
Not really other than knowing more precisely where it is, Welles. In terms of development around it, we're ways out on that, and we didn't include any of that in the value as we've spoken to before in and around that fault.
So, that's something that we'll be looking at over a longer term and I think when we start to look at that, it also is something I think we can manage very effectively around with that seismic and the information on the wells in and around there that are already existing.
Barton R. Brookman - PDC Energy, Inc.
Welles, we actually met with the Delaware team yesterday extensively and I believe the number was we have 3D over 90% of our acreage position today. So, we feel really good about that.
Welles W. Fitzpatrick - Johnson Rice & Co. LLC
Okay. That's perfect.
Thank you guys so much.
Operator
Our next question comes from Michael Glick with JPMorgan.
Michael A. Glick - JPMorgan Securities LLC
Good morning. If we look at your production forecast, is that based on your current type curves or does it assume any uplift from tighter stage spacing or enhanced completions in the Wattenberg?
Scott J. Reasoner - PDC Energy, Inc.
It's definitely based on our current type curves. We don't have that uplift in our expectations at this point.
Obviously, you're seeing very early data and this is just hot off the press in terms of the amount of time we have in there and so on.
Michael A. Glick - JPMorgan Securities LLC
Got you. And then just on the Argentine well, I guess it's a bit challenging with your choke management program.
But do you expect that well to trend closer to the prior three wells over time and how does that completion on that well vary compared to the prior areas of the operated wells?
Scott J. Reasoner - PDC Energy, Inc.
Those are great questions. I appreciate that.
Because we see that Argentine well is very competitive with the other three wells, we have held it back more with the choke systems. It's one of our may be more conservative looks at that.
We're not sure if that's going to be beneficial long term or not yet, but that's part of what we're doing with that test. It's something that we have done in the Wattenberg and we've done that in Utica, the Marcellus, and it has paid dividends.
So, a little more conservative maybe than the prior team that was working on that. And when you look at that well, we see it competing directly with these other wells and don't see – I guess in terms of the process of completion, we mirrored these other three wells.
The completion process as nearly as possible and feel like we got a very good execution on that completion.
Michael A. Glick - JPMorgan Securities LLC
Got you. Thank you very much.
Operator
Our next question comes from David Deckelbaum with KeyBanc.
David A. Deckelbaum - KeyBanc Capital Markets, Inc.
Morning, Barton, Scott. Thanks for taking my questions.
Barton R. Brookman - PDC Energy, Inc.
Morning, David.
David A. Deckelbaum - KeyBanc Capital Markets, Inc.
Just curious if you could give any color on to the thought process of bringing in this Delaware Basin rig a bit earlier in the program. Is it predominantly just to take it after the HBP faster?
Is it to gather more data faster? And how is this sort of influencing that multi-year program that you guys have laid out around the acquisition?
Scott J. Reasoner - PDC Energy, Inc.
We really have two benefits that we see in that. You described one of them very effectively.
The HBP-ing the acreage, we're moving that forward more quickly. We do have some requirements that we wanted to make sure that we met, and it's something that we're really excited in that we're going to be working in the areas where we're going to be generating value.
So, that didn't seem like any kind of a stretch for us. And in addition to that, we found a rig we really like and it's one of those that's, I would say, built for purpose down there and makes us what we hope to be more efficient as we go through the year, as we get the benefit from those rigs that are definitely suited for this type of operation.
Lance A. Lauck - PDC Energy, Inc.
David, for 2018, we were projecting around five rigs from the Delaware Basin when we rolled out the acquisition. So, bringing in this third rig here in 2017, I think we're still on pace to have kind of a reasonable close proximity of what we outlined there in August.
So, we feel very comfortable to how that's playing in.
Barton R. Brookman - PDC Energy, Inc.
But I – and this is Bart – I do believe this decision absolutely, David, will give us additional technical data in completions and drilling and the design of this rig as we go forward that will all be benefits in our overall process as we go into 2018. So we view this, and a lot of the turn-in lines are towards the end of the year which will be a nice contribution to our 2018 production base.
David A. Deckelbaum - KeyBanc Capital Markets, Inc.
I appreciate the color, guys. And then if I could just ask one on the Wattenberg.
Scott, you talked about the enhancements and, Bart, I think you discussed them as well, just what you're seeing in the Wattenberg right now. And we've seen really good data coming out of the XRLs on some of that Noble acreage that you guys swapped into last year.
Is there, one, I guess I just want to understand, are most of the enhancements, would you kind of summarize it for most laymen as stage spacing enhancements. Are there other things that you guys planning on testing this year?
And two, I guess, is there anything that you're seeing right now, I guess, that would motivate you to look into the Outer Core a little bit more with some of the enhancements that you have seen?
Scott J. Reasoner - PDC Energy, Inc.
I can make a run at that question and I hope I cover all of that; quite a few different pieces there. In terms of what we believe is contributing to that, we definitely think the stage spacing is contributing, and as we go forward through this year, we're planning on trying more 140-foot spacing, we're at 170 foot is our standard right now.
We're going toward 100 feet in a number of tests. I'm sorry, going to 140 feet in a number of tests and maybe going down to 100 feet as we see the benefits of the 140.
We also see the testing that we're doing moving toward additional sand even though our LDS didn't show a lot of differential between the 1,100 and 1,800 pound per foot type loading. We're definitely moving toward trying additional sand with the idea that many of our peer companies out there are saying it's working tremendously, and we just want to make sure we give that an adequate test to make sure we understand it.
In addition, we've got a number of other things that we still plan on trying. We've got some management of the perf systems that we use.
The way we set our perfs up in a particular stage is something we're looking at. The surfactants are still something that we're going to be looking toward understanding the impacts they have, both positive and potentially negative.
And then obviously there's still fluid design. We've run a slickwater test that we weren't overly excited about, but we'll probably look at that again because some of our peers are out there using slickwater jobs.
And then finally, just overall continuing to manage around the chokes. And we're continuing to experiment with more aggressive chokes as we get into the longer laterals, with the idea that we believe we can move that fluid a little bit quicker as you have a longer lateral and what you'd call a bigger tank, I guess, if you want to put it that way.
Barton R. Brookman - PDC Energy, Inc.
And, David, on the Outer Core portion of the question, this year, our plans are obviously really set with our permitting process and our planning group within the Wattenberg. And the bulk of our drilling, virtually 100% is in this, call it the swap block.
So, they're in 5 of 64 and 5 of 65 within the Middle Core region. Yes, our teams are looking at some of the recent announcements around enhanced completion designs in the Outer Core.
And I think if there's any expectation on that, obviously commodity prices have a lot to do with this. We're very pleased with the reserve levels we're getting in the Middle Core region right now, but we'll be reviewing that, incorporating all of that into our 2018 plans.
But don't expect us to shift our drilling plans right now within the core Wattenberg. They're pretty set in stone for the year.
David A. Deckelbaum - KeyBanc Capital Markets, Inc.
Got it. Thank you for all the color, guys.
Operator
Our next question comes from John Nelson with Goldman Sachs.
John Nelson - Goldman Sachs & Co.
Good morning and congratulations to David for joining the team.
David W. Honeyfield - PDC Energy, Inc.
Thank you.
Barton R. Brookman - PDC Energy, Inc.
Good morning.
John Nelson - Goldman Sachs & Co.
I wanted to come back – good morning – I wanted to come back to David's question on kind of the impetus for the 2017 capital reallocation. And just to kind of be clear, was any of the redirect based on greater concerns that DJ Basin midstream capacity might potentially be closer to filling up?
And then secondly, now that we do have more capital earmarked for a more oily Permian, should we be thinking about that oil mix now towards the high-end of the – I think you guys gave 41% to 45% range previously or how should we think about that?
Lance A. Lauck - PDC Energy, Inc.
So yeah. John, this is Lance.
As far as the DCP and all of the midstream within the Wattenberg, we feel very comfortable with the current capacities that they have for gas gathering, the (36:44) and processing out of the field. As they've already announced in June or July, they'll have a bypass of around 30 million to 40 million cubic feet per day that'll go in place.
And then, their Plant 10 that they are working on will be in place in the fourth quarter of 2018. So we have been working very closely with DCP and a great relationship there.
And so we're working together in modeling out the volumes going forward. So the capital adjustments didn't have anything to do with the takeaway out of the DJ Basin Field.
Barton R. Brookman - PDC Energy, Inc.
And, John, on the 43% liquid mix, I don't think we are moving our guidance. I think we've got a 41% to 45% range out there with a midpoint of 43%.
I think that number holds primarily because the mix as we go through the year even though we're deploying a rig a little early, the third rig in the Delaware really with the way drilling is and the completions and the complexities of all that, maybe in the fourth quarter late in the year we're going to see that start contributing. So, we're not really going to be skewing the overall 2017 production, but I think it is back to our early discussion, I think it will have some oily impacts on 2018 as we get it and really start looking at the 2018 production forecast.
John Nelson - Goldman Sachs & Co.
That's really helpful color. I'll let somebody else hop on.
Congrats.
Operator
Our next question comes from Neal Dingmann with SunTrust.
Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.
Bart, for you, Scott, I'm looking just I think at your prior slides, I want to make sure, number one, that I should say the Delaware Basin, the one that you've kind of just layout, is the current rigs right now, the two rigs, are you in that Western and Eastern, and I just want to make clear where you brought that third rig?
Scott J. Reasoner - PDC Energy, Inc.
Yeah. We've got one running out in the Western acreage, it's on the second well out there.
We drilled one and we'll be completing it the next – it will be about a month from now. The second well has just been spud recently.
The other two rigs are out there running in the Eastern acreage. And the one has just rigged up, it probably spud yesterday, the new one.
So that's the status on it. But two in the East and one in the West.
Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.
And any plan, Scott, near-term for anything on the Central?
Scott J. Reasoner - PDC Energy, Inc.
Yeah. When you look at our plan over the year, really, we're going to be pretty well balanced between – we're taking the two wells out for the Western acreage.
We'll be pretty well balanced between the Western and the Central in terms of drilling, and I think that pretty well describes it. I'm sorry, Eastern and Central.
Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.
Yeah.
Scott J. Reasoner - PDC Energy, Inc.
I'm sorry; I'm getting my directions mixed up.
Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.
Eastern and Central you meant.
Scott J. Reasoner - PDC Energy, Inc.
I'm sorry. Yes.
Split evenly between the Eastern and Central.
Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.
Okay. And then just lastly, on that same – you talked about sort of the budgeted cost there.
What – Scott, as far as single-well pad versus multi or four-well pads, what – any idea on when you kind of laid out the CapEx plan? How you're thinking about that in the Delaware, will most of it be multi-well or anything you could comment around there?
Scott J. Reasoner - PDC Energy, Inc.
At this point, we've got about three or four pads that are going to be multi-well pads. And so, we'll be benefiting from that and I think the differential we're looking at is still the same.
So if you reduce the $7.1 million, one mile or by about $500,000 or $600,000, that's probably pretty accurate. And so, we're going to – but we will get the benefit from some of those efficiencies as we drill multi-well laterals off a pad.
It's something that we're only going to get to do a small amount of this year because many of those – the wells we're drilling this year are HBP-ing acreage.
Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.
It makes sense. Thanks so much for the details.
Operator
Our next question comes from Dan McSpirit with BMO Capital Markets.
Daniel Eugene McSpirit - BMO Capital Markets (United States)
Thank you, folks. Good morning.
Scott J. Reasoner - PDC Energy, Inc.
Good morning.
Daniel Eugene McSpirit - BMO Capital Markets (United States)
As more capital is put to work in the Delaware Basin over time, how do you see operating cost and price differentials trending? Just hoping you could sketch for us what that might look like beyond 2017.
How broad the strokes? Just really asking for modeling purposes.
Scott J. Reasoner - PDC Energy, Inc.
Okay. When you talk about operating expenses, we're really seeing that, overall, for the company, that $3 may be a little bit north of there as we get more impact from the Delaware over the longer term.
For next year, we're seeing that $3 range, as David described, overall. When you start talking about the Delaware early in the life of these wells, you're talking about wells that flow and flow very effectively, as they age is when the additional operating expenses come in.
So, that'll be in the next several years. We'll see those wells that are currently coming on line starting to shift over to some type of artificial lift program.
But that's got some delay in it. So, really that's why it will be gradually ratcheting up as the volumes ratchet up and the number of wells that we get, I guess, are ageing, if you want to say that, say it that way, are coming into the fray and needing additional help in lifting the liquids.
Barton R. Brookman - PDC Energy, Inc.
And, Dan, this is Bart. Just on a very, very high level what to expect as we go forward here probably into 2018 and 2019, I think based on what we know today, and to Scott's point, some of these Delaware costs are new to us, and we're learning a lot.
But I think we've got a pretty good handle on where we're headed, particularly as we need artificial lift in that basin. But overall, I think you're going to expect that Delaware to be in that $4 to $5 range going forward.
And the Wattenberg, we've been incredibly pleased with our cost structure. We've got great growth in that basin.
Our teams are doing a phenomenal job of managing their costs. So, we really – we're hopeful that we can hold around that $3 in the Wattenberg.
So, as you're modeling out and thinking long term, and then it comes down to the production profile from the two basins which I think Lance has laid out some of those thoughts early when we rolled out the deal. But we'll update a lot of that at Analyst Day as far as our long-term forecasting.
Daniel Eugene McSpirit - BMO Capital Markets (United States)
I appreciate the detail there. It's very helpful.
And as a follow-up to that, how much acreage is approximate to the Grisham Fault that could be off limits given the geologic risk? Again, just asking for modeling purposes here.
Lance A. Lauck - PDC Energy, Inc.
Dan, this is Lance. We've kind of done a quick look at that.
And so, I would say in proximity sort of in that very southern area of the Central acreage block that we're – let's just say, it's approximately 5,000 acres plus or minus. Now, that said, I'd definitely say it's off limits.
What I would say is that we just got to do the work from a 3D seismic standpoint and understand the fault displacements and clearly we can drill on either side of the fault itself. We just want to make sure that we're not in a place where there's a significant throw of a fault and we're trying to drill across it.
We want to make sure we manage that. And this is something that we've managed many times in the past in different areas.
So, we feel very comfortable about our ability to do this. And then just to summarize, just to keep in mind, the locations that we have in our Delaware Basin, none of them are in and around this Grisham Fault acreage position.
Daniel Eugene McSpirit - BMO Capital Markets (United States)
Got it. Thank you.
Have a great day.
Lance A. Lauck - PDC Energy, Inc.
Thanks, Dan.
Operator
Our next question comes from David Tameron with Wells Fargo.
David R. Tameron - Wells Fargo Securities LLC
Good morning. Whoever, I don't know, Bart or Lance or David, whoever wants to take this, I'm just trying to dig in the capital budget a little more.
If I think about that $725 million and $775 million, it says you have additional seven turn-in line wells and then some additional cost increase in the Permian, are you – is your Wattenberg capital forecast lower than it was prior or I'm just trying to figure out the math on that?
Barton R. Brookman - PDC Energy, Inc.
Scottie?
Scott J. Reasoner - PDC Energy, Inc.
Yeah, David. This is Scott.
We definitely have our Wattenberg capital a bit lower. We're about $20 million lower there.
And that's really a function of the reduced turn-in-lines that we have there down some. And then also we've shifted a working interest from some of the wells we have this year to a lesser number as we determine that we're not going to have that additional interest that we once thought we would have.
And really it's those two factors as well as the efficiencies that we've seen from the cost structure that make up that entire combination to get us to $20 million. And then you also see the Utica contributing to the reduction as well.
There is about $15 million less associated with not drilling the two wells that we had originally planned for in the Utica.
David R. Tameron - Wells Fargo Securities LLC
Okay.
Barton R. Brookman - PDC Energy, Inc.
And, David, that's offset by the increased cost that Scott covered, that we've covered in detail. Deployment of the rig earlier and then also some additional midstream costs in Delaware we're building out really with pre-planning as we've continue to understand those assets and investing for the – look at that as investing for the future for the long-term drilling programs.
David R. Tameron - Wells Fargo Securities LLC
No, that makes sense. Is there any clock ticking in the Utica as far as when you have to drill those wells by?
Scott J. Reasoner - PDC Energy, Inc.
Yeah. We talked about that quite a bit, David.
We have a significant amount of acreage expiring this year and on the order of $30 million we've spoken to much of that is in the south and the wells in the north. We are basically at a place where we can continue with those and drill those into next year, we do have a small amount of acreage that we would be losing associated with that.
But we're looking to try to extend that and that's part of the budget that we have available to us now. You can see that's a very small number.
But really not anything pressing on us hard, the Southern acreage we aren't planning to extend that for obvious reasons around that amazing performance.
David R. Tameron - Wells Fargo Securities LLC
Okay. Yeah.
And I also want to say congrats to David Honeyfield for joining. But I have one last question for Scott.
The frac jobs, you've talked about using more sand and some of what your peers are doing, et cetera, in the Wattenberg. How aggressive are you going to get on that, and what are you doing today?
How much – what should we think about going forward? Can you give us some more color on that?
Scott J. Reasoner - PDC Energy, Inc.
Sure. Our standard is about 1,100 pounds a foot, David.
And we really see the benefits of that compared to the 1,800 pounds per foot that we ran in the LDS. We didn't see a lot of uplift.
But we do plan to continue testing, 1,300 pounds a foot on a number of wells is where we're headed, and if that looks like it's contributing a reasonable amount of production or got to pay for that additional sand, obviously, we're also considering 1,500 pounds a foot, just to see if there's a sweet spot in there that we're missing between the 1,100 and 1,800 is really what we're shooting for. And then we'll continue watching our peers.
I mean, like I said, they're doing a tremendous amount of work out there that we can follow, and hopefully there's continued information around that that we can gain knowledge from.
David R. Tameron - Wells Fargo Securities LLC
Okay. Helpful color.
I appreciate it.
Operator
Our next question comes from Kyle Rhodes with RBC.
Kyle Rhodes - RBC Capital Markets LLC
Hey. Morning, guys.
Just kind of following on to David's question. What's the working interest for the Wattenberg turn-in lines in 2017, the new working interest?
Scott J. Reasoner - PDC Energy, Inc.
Yeah. We're in the low 80s for the year.
Kyle Rhodes - RBC Capital Markets LLC
Great. Okay.
Thanks. And then I guess on the budget, does the $775 million, does that include any of the potential extension payments in the Utica?
Scott J. Reasoner - PDC Energy, Inc.
Yes, it does. There's about $3 million in there for extension of leases, and like I said, that's a small number of acres that are in that northern acreage that we're looking at.
Kyle Rhodes - RBC Capital Markets LLC
Got it. And I guess kind of the timing of the strategic review, is that something we should expect more color on with Analyst Day or?
Lance A. Lauck - PDC Energy, Inc.
Our plans there are to announce our position with Utica probably in the first half of this year. So, we've got some work to do.
We've got the wells we drilled last year. We want to monitor the performance and then just take a good look about how it fits within the portfolio and how it compares from a capital efficiency standpoint.
So, we've got some work ahead of us, but we anticipate being able to announce this here in the first half of the year.
Kyle Rhodes - RBC Capital Markets LLC
Great. And just one last one from me, if I could.
It looks like oil diffs continue to tighten pretty nicely in the Wattenberg. How do you guys think about I guess Wattenberg differentials longer term now?
I guess when do you guys see some of those longer haul pipes actually getting filled?
Lance A. Lauck - PDC Energy, Inc.
I'd say from where we sit today, we're very encouraged with where we sit as far as production from the field versus takeaway from the field. And so, we are around that $3.50 a barrel sort of differential not including TG&P from the Wattenberg Field.
And when you look out through 2020, let's say, there's a lot of capacity still that's available out of the field. And when you think about the pace of drilling for oil in the Wattenberg Field and how that could look over the next few years, we feel comfortable that there'll still be additional opportunities to put oil on pipe out of the basin.
So, when we think about differential longer term, we think that we like the sort of $3.50 or so, plus or minus. It could get a little better here depending upon sort of the production from the field and the takeaway capacity.
But we see it being favorable here for some period of time.
Kyle Rhodes - RBC Capital Markets LLC
That's helpful, guys. Appreciate all the color.
Operator
Our next question comes from Jeffrey Campbell with Tuohy Brothers.
Jeffrey L. Campbell - Tuohy Brothers Investment Research, Inc.
Good morning.
Barton R. Brookman - PDC Energy, Inc.
Hi, Jeff.
Jeffrey L. Campbell - Tuohy Brothers Investment Research, Inc.
Returning to the Wattenberg spacing, your recent presentation show that the Cockroft pad, 145-foot wells appear to have slightly outperformed the 170-foot wells. So just sort of a little bunch of short questions.
Was this your expectation? How were the wells completed?
Did you rate restrict both of the spacing regimes? And how's the production holding up presently?
Scott J. Reasoner - PDC Energy, Inc.
You're correct. We have the 140-foot test in that Cockroft pad as well, and they are outperforming slightly.
We really completed the wells similarly. Other than that, we took the fluid that we would normally pump in the entire wellbore, divided it among all the wells and also the sand the same way, all the stages, also the sand the same way such that we got a fairly effective test there.
That's why we continue pushing toward the lower stage spacing on the tests that we plan on conducting this year. It's such that with what we saw between the 200 and 170, you just don't, with our approach to this, we just don't see that as suddenly hitting the optimum.
We'll continue to test the 140 and see if it continues to perform the way it is, the way it's doing on the Cockroft. And we're seeing those results continue on basically that you saw on the early date in the Cockrofts.
When you talk about what we could do, we could go to a 100 feet very easily and that's nearly what we're – we're in that 100 to 125-foot stage spacing range in the Delaware. So, we're considering that.
It's a little early for us to go there, but I think the teams will be doing that sometime this year based on what they're seeing. But the nice thing about stage spacing is it's not as expensive as the sand.
So, it's only a small amount of uplift in costs relative to the sand particularly. When we talked before about this, we were talking $50,000 to go from 200 foot per stage to 170 foot per stage.
And so something similar probably going from 170 to 140 is a reasonable number.
Jeffrey L. Campbell - Tuohy Brothers Investment Research, Inc.
Okay, well that's helpful color. As a follow-up, I was just wondering, will you do any selective exploration in emerging secondary zones in the Delaware Basin in 2017, or does that wait for 2018 and beyond?
Scott J. Reasoner - PDC Energy, Inc.
We're at a point right now where we're very much focused on the A and B zones in the Wolfcamp. In understanding that, I would say that the major test that we're conducting this year will be in that Western acreage, those two wells that we're planning – that we're currently drilling out there, and really watching those carefully.
The remainder of the wells really have to stay focused on HBP-ing acreage and understanding on the Central region particularly the A and B combinations, we would love to get that understood. And we get to do a little bit of that later this year and early next year.
Beyond that, in 2018, we'll probably start looking at some of those other zones, but we're going to be very busy, like I said, in 2017 staying on the A and B zones.
Jeffrey L. Campbell - Tuohy Brothers Investment Research, Inc.
Okay. That makes sense.
Thank you. Appreciate it.
Operator
And I'm not showing any further questions at this time. I'd like to turn the call back over to Bart Brookman.
Barton R. Brookman - PDC Energy, Inc.
Yeah. Thank you, Kevin, and thank you, everyone, for attending the call and your ongoing support in the PDC team.
Operator
Ladies and gentlemen, this does conclude today's presentation. You may now disconnect, and have a wonderful day.