PDC Energy Inc (PDCE) 2016 Q4 法說會逐字稿

Good day, ladies and gentlemen and welcome to the PDC Energy fourth-quarter 2016 conference call. (Operator Instructions). As a reminder, today's conference is being recorded. I would now like to introduce your host for today's conference call, Mr. Mike Edwards, Senior Director of Investor Relations. Please go ahead, sir.

Good morning, everyone. 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'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 the forward-looking statements on slide 2 of that presentation. We will present some non-US GAAP financial numbers on today's call, so I would 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 will turn the call over to Bart Brookman, our CEO. Bart.

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 and we are 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 and 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 costs. That is down from $3.71 per BOE in 2015, a 27% reduction. This coupled with reduced [deducts] 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 of 2.1, 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, 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 produced 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 in the Wattenberg and 2 in our Utica project.

So where do we stand today? We are pleased that our production levels in our guidance remain 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 completions side. Again, we plan on executing this capital program while strengthening the balance sheet through 2017 with year-end debt to EBITDA expected to be 1.7.

And last, in 2017, expect continued 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 in 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.

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 acquisitions, 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 7000 barrels of oil equivalent per day. Due to the timing of turn-in-lines and midstream facility upgrades, December production averaged approximately 5700 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 6500 BOE per day. This production is expected to continue growing as we have a full-time 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 will 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 have 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've 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 have 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 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 are 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 pads 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 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 have 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 of oil equivalent type curve and is averaging approximately 70% oil.

We are 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 costs 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 have 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 are very encouraged with the early results we are seeing and as we discussed 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 will turn the call over to David for a financial review. David.

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 derive 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, this takes 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 deducts, 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 will have more on this in a minute as we expect to continue to see the downward trend in our G&A costs 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.

The 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 of the year prior.

Similarly, adjusted EBITDA for 2016, which includes the addback 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 in that we settled the convert issue that was due in 2016, we issued a new convertible note that has a 1 1/8 coupon, we issued $400 million in senior notes priced at 6 1/8 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 utilize 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 have 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 30 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 have 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 to 33 million BOE and our expectations that will be near the top end of our capital investment range of $775 million. So here we are 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 the Saddle Butte crude oil gathering system. We continue to pursue this strategy of oil piping arrangements out of the Wattenberg as it serves to reduce truck traffic in the field.

Lastly, we are 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 as 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 will now turn the call back to the operator for Q&A.

(Operator Instructions). Steve Berman, Canaccord.

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?

Yes, I can give you a little flavor. We have 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 is something that is in terms of trying to lock that in, most of the suppliers look at you and say, you know what, we are 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 service as 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 and just a little bit, but stay connected overall because the service goes away if your costs get to low relative to the other folks that are paying out there.

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 Reasoner

Yes. Really see that distributed about and I'm going to give you percentages that are good approximations. There is 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.

And Steve, I do believe the XRLs we've got a weighting towards the second half of the year, if I remember correctly.

Perfect. Thanks, Bart. Thanks, Scott.

Welles Fitzpatrick, Johnson Rice.

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?

On the midstream side of the Delaware Basin, the volumes we currently have going through it are primarily equity volumes that we have from our Company. Obviously part of the volumes going through that are the royalty volumes as well.

So 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 are very much focused on and we will continue to think about going forward. That is what we said today on wells.

Okay, perfect. And then another in the same area. I think you guys were 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?

We did acquire 3D seismic to cover really most of our play out there, 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 are a ways out on that and we didn't include any of that in the value as we have spoken to before in and around that fault.

So that is something that we will 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.

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.

Okay. That's perfect. Thank you guys so much.

Michael Glick, JPMorgan.

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?

It's definitely based on our current type curves. We don't have that uplift in our expectations at this point. Obviously you are 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.

Got you. And then just on the Argentine well, I guess it's a bit challenging with your choke management program, but do expect that well to trend closer to the prior three wells over time and how did that completion on that well vary compared to the prior Arris-operated wells?

Those are great questions. I appreciate that because we see that Argentine well as very competitive with the other three wells. We have held it back more with the choke systems. It's one of our maybe more conservative looks at that. We are not sure if that's going to be beneficial long term or not yet, but that's part of what we are doing with that test. It is something that we have done in the Wattenberg and we've done that in the 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 processes, as nearly as possible and feel like we got a very good execution on that completion.

Got you. Thank you very much.

David Deckelbaum, KeyBanc.

Curious if you could give any color on the thought process of bringing in this Delaware Basin rig a bit earlier in the program? Is it predominantly just to get after the HBP faster? Is it to gather more data faster and how is this influencing that multiyear program that you guys have laid out around the acquisition?

We really have two benefits that we see and you described one of them very effectively. HBPing the acreage, we are moving that forward more quickly. We do have some requirements that we wanted to make sure that we met and it is something that we are really excited in that we are going to be working in the areas where we are 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 I would say is 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.

David, for 2018, we were projecting around five rigs from the Delaware Basis when we rolled out the acquisition. So bringing in this third rig here in 2017, I think we are still on pace to have a reasonable close proximity of what we outlined there in August. So we feel very comfortable with how that is playing in.

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.

I appreciate that 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 are seeing in the Wattenberg right now. We have seen really good data coming out of the XRLs on some of that Noble acres that you guys swapped into last year.

Is there -- one, I guess I just want to understand are most of the enhancements, would you summarize it for most laymen, as stage spacing enhancements? Are there other things that you guys are planning on testing this year? And two, I guess, is there anything that you are 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?

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 are planning on trying more 140 foot spacing. We are at 170 foot is our standard right now. We are going toward 100 feet in a number of tests -- I'm sorry -- going toward 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 are doing moving toward additional sand. Even though our LDS didn't show a lot of differential between the 1100 and 1800 pound per foot type loading, we are definitely moving toward trying additional sand with the idea that many of our peer companies out there are saying it is 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 are looking at. The surfactants are still something that we are 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 will 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 are 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 would call a bigger tank I guess if you want to put it that way.

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 swap block there in [5064] and [5065] 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 are very pleased with the reserve levels we are getting in the middle core region right now, but we will be reviewing that, incorporating all that into our 2018 plans. But don't expect us to shift our drilling plans right now within the core Wattenberg. They are pretty set in stone for the year.

Got it. Thank you for all the color, guys.

John Nelson, Goldman Sachs.

Good morning and congratulations to David for joining the team. I wanted to come back to David's question on the impetus for the 2017 capital reallocation and just to be clear, was any of the redirect based on greater concerns that the 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 a 41% to 45% previously, or how should we think about that?

So 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 and fractionization and processing out of the field. As they have already announced, in June or July, they will have a bypass around 30 million to 40 million cubic feet per day that will 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 are working together and modeling out the volumes going forward. So the capital adjustments didn't have anything to do with that takeaway out of the DJ Basin, the field.

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 are 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 may be in the fourth quarter, late in the year, we're going to see that start contributing.

So we are not really going to be skewing the overall 2017 production, but I think it is, back to our earlier discussion, I think it will have some oily impacts on 2018 as we get in and really start looking at the 2018 production forecast.

That's really helpful color. I will let somebody else hop on. Congrats.

Neal Dingmann, SunTrust.

Bart, for you or Scott, I'm looking just I think at your prior slides. I want to make sure, number one, that they actually say the Delaware Basin, the one where you lay out -- is the current rigs right now, the two rigs, are you in the Western and Eastern? And I just want to make clear where you brought that third rig.

Yes. We've got one running on the Western acreage. It's on a second well out there. We've drilled one and we will be completing it -- 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. Two in the East and one in the West.

Any plans, Scott, near term for anything in the central?

Yes, when you look at our plan over the year, really we are going to be pretty well-balanced between -- taking the two wells out for the Western acreage, we will be pretty well-balanced between the Western and Central in terms of drilling and I think that pretty well describes it -- I'm sorry, Eastern and Central. I'm getting my directions mixed up.

Eastern and Central you meant?

I'm sorry, yes. Split evenly between the Eastern and Central.

Okay. And then just lastly, on that same, you talked about the budgeted costs there. Scott, as far as single-well pads versus multi or four-well pads, any idea on when you laid out the CapEx plan how you are thinking about that in the Delaware? Will most of it be multi-well or anything you could comment around there?

At this point, we've got about three or four pads that are going to be multi-well pads and so we will be benefiting from that and I think the differential we are looking at is still the same. So if you reduce the $7.1 million one-miler by about $500,000 or $600,000, that's probably pretty accurate.

And so -- but we will get the benefit from some of those efficiencies as we drill multi-well laterals off of pads. It's something that we are only going to get to do a small amount of this year because many of the wells that we are drilling this year are HBPing acreage.

Makes sense. Thanks so much for the details.

Dan McSpirit, BMO Capital Markets.

As more capital is put to work in the Delaware Basin over time, how do you see operating costs and price differentials trending? Just hoping you could sketch for us what that might look like beyond 2017, however broad the strokes. Just really asking for modeling purposes.

Okay. When you talk about operating expenses, we are really seeing that overall for the Company that $3 maybe a little bit north of there as we get more impact from the Delaware. Over the longer term for next year, we are seeing that $3 range, as David described, overall.

When you start talking about the Delaware, early in the life of these wells, you are talking about wells that flow and flow very effectively. As they age is when the additional operating expenses come in, so that will be in the next several years, we will see those wells that are currently coming online starting to shift over to some type of artificial lift program. But that's got some delay in it. So really that's what it will be gradually ratcheting up as the volumes ratchet up and the number of wells that we get I guess our aging, if you want to say it that way, are coming into the fray and needing additional help in lifting the liquids.

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 are learning a lot, but I think we've got a pretty good handle on where we are headed, particularly as we need artificial lift in that basin.

But, overall, I think you can expect the 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 are hopeful that we can hold around that 3 in the Wattenberg.

So as you are modeling out and thinking long term, 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 will update a lot of that at Analysts Day as far as our long-term forecasting.

I appreciate the detail there. It's very helpful. And as a follow-up to that, how much acreage is proximate to the Grisham fault that could be off-limits given the geologic risk? Again, just asking for modeling purposes here.

We've done a quick look at that and I would say, in proximity of it, in that very southern area of the central acreage block, let's just say it's approximately 5000 acres plus or minus. Now, that said, I definitely would say it's off limits. What I would say is we've 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 are not in a place where there's a significant throw of a fault and we are trying to drill across it. We want to make sure we manage that and this is something that we have 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.

Got it. Thank you. Have a great day.

David Tameron, Wells Fargo.

Bart or Lance or David, whoever wants to take this. I'm just trying to dig into the capital budget a little more. If I think about that $725 million to $775 million, it says you have an additional seven turn-in-line wells and then some additional cost increases in the Permian. Is your Wattenberg capital forecast lower than it was prior, or -- I'm just trying to figure out the math on that?

We definitely have our Wattenberg capital a bit lower. We are 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 determined 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 have 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's about $15 million less associated with not drilling the two wells that we had originally planned for in the Utica.

And David, that's offset by the increased costs that Scott covered that we've covered in detail, deployment of the rig earlier and then also some additional midstream costs in Delaware where we are building now. It's really preplanning as we've continued to understand those assets and investing -- look at that as investing for the future for the long-term drilling programs.

No, that makes sense. Is there any clock ticking in the Utica as far as when you have to drill those wells by?

Yes, we've talked about that quite a bit, David. We have a significant amount of acreage expiring this year, on the order of $30 million we have spoken to. Much of that is in the south. 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 are looking to try to extend that and that is part of the budget that we have available to us now. As 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 Mason, the Mason performance.

Okay. Yes, I also wanted 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, etc. in the Wattenberg. How aggressive are you going to get on that and what are you doing today and what should we think about going forward? Can you give us some more color around that?

Sure. Our standard is about 1100 pounds a foot, David. We really see the benefits of that. Compared to the 1800 pounds per foot that we ran in the LDS, we didn't see a lot of uplift, but we do plan to continue testing; 1300 pounds a foot on a number of wells is where we are headed and if that looks like it's contributing a reasonable amount of production or -- we've got to pay for that additional sand, obviously. We are also considering 1500 pounds a foot just to see if there's a sweet spot in there that we are missing between the 1100 and 1800 is really what we are shooting for.

And then we will continue watching our peers. Like I said, they are doing a tremendous amount of work out there that we can follow and hopefully there is continued information around that that we can gain knowledge from.

Okay. Helpful color. I appreciate it.

Kyle Rhodes, RBC.

Just following on to David's question. What's the working interest for the Wattenberg turn-in-lines in 2017, the new working interest?

We are in the low 80s for the year.

Okay, great. Thanks. On the budget, does the $775 million, does that include any of the potential extension payments in the Utica?

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 are looking at.

Got it. And I guess the timing of the strategic review, is that something we should expect more color on with Analyst Day or --?

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.

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 Wattenberg differentials longer term now? When do you guys see some of those longer-haul pipes actually getting filled?

I would say from where we sit today, we are 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 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 will still be additional opportunities to put oil on pipe out of the basin.

So when we think about differential longer term, we think we like the $3.50 or so plus or minus. It could get a little better here depending upon the production from the field and the takeaway capacity, but we see it being favorable here for some period of time.

That's helpful, guys. Appreciate all the color.

(Operator Instructions) Jeffrey Campbell, Tuohy Brothers.

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 a bunch of short questions. Was this your expectation; how were the wells completed; did you rate-restrict both of the spacing regimes and how is the production holding up presently?

You are 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 will continue to test the 140 and see if it continues to perform the way it is, the way it is doing on the Cockroft and we are seeing those results continue on basically that you saw in the early data in the Cockroft.

When you talk about what we could do, we could go to 100 feet very easily and that's nearly what we're -- we are in that 100 to 125 foot stage spacing range in the Delaware, so we are considering that. It's a little early for us to go there, but I think the teams will be doing that sometime next year based on what they are seeing.

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 cost 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.

Okay. 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.

We are at a point right now where we are very much focused on the A and B zones in the Wolfcamp and understanding that. I would say that the major tests that we are conducting this year will be in that Western acreage, those two wells that we are currently drilling out there and really watching those carefully.

The remainder of the wells really have to stay focused on HBPing acreage and understanding in 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 will probably start looking at some of those other zones, but we are going to be very busy, like I said, in 2017 staying on the A and B zones.

Okay, that makes sense. Thank you. Appreciate it.

I'm not showing any further questions at this time. I would like to turn the call back over to Bart Brookman.

Thank you, Kevin and thank you, everyone, for attending the call and your ongoing support in the PDC team.

Ladies and gentlemen, this does conclude today's presentation. You may now disconnect and have a wonderful day.