PDC Energy Inc (PDCE) 2018 Q3 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the PDC Energy Third Quarter 2018 Conference Call. (Operator Instructions) As a reminder, this conference call is being recorded.

I would now like to introduce your host for today's conference, Mr. Mike Edwards, Senior Director of Investor Relations. Sir, you may begin.

Good morning, everyone, and welcome. On the call today, we have Bart Brookman, President and CEO; Lance Lauck, Executive Vice President; Scott Reasoner, Chief Operating Officer; and Scott Meyers, Chief Financial Officer.

Yesterday afternoon, we issued our press release and posted the slide presentation that accompanies our remarks today. We also filed our 10-Q. The press release and presentation are available on the Investor Relations page of our website, which is pdce.com.

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

With that, we can get started. I'll turn the call over to Bart Brookman, our CEO.

Thank you, Mike, and hello, everyone. Let me begin by highlighting what we consider a strong third quarter. Production for the company, 10.1 million barrels of oil equivalent or 110,000 BOE per day, a 21% improvement from the same quarter last year and a 6% improvement in daily volumes from the second quarter of 2018.

Oil production mix for the company, 43%. In the Wattenberg, our total production was under internal expectations due to continued midstream constraints and delays in new residue takeaways in the basin. I should note, these take away projects are anticipated to be online early November.

In the Delaware Basin, production exceeded expectations yet again. And we continue to be very pleased with the overall operational results in Texas, including ongoing improvements in our drill times; completion designs and production results, which include the Grizzly pad downspace test; water management, where we continue to move virtually 100% of our water on pipe; our midstream build-out; and our marketing efforts in the Delaware, where we have confidence in our flow assurances and our net back on oil for the quarter was 94% of NYMEX, a terrific accomplishment, given the current Permian marketing environment.

Operationally for the company, we spud 51 wells, turned-in-line 32, a cap spend for the quarter of $273 million. I should note, we are on target to meet the midpoint of our guidance of approximately $970 million, and our operational pace for 2018 is in line with our expectations.

Financially for the quarter. First, I'm happy to announce we increased our borrowing commitment to $1.3 billion, giving us dramatic improvement in our financial flexibility as we head into next year. Our leverage ratio, 1.6, has thus continued to improve quarter-by-quarter. Adjusted cash flow from operations, $201 million. And lifting cost for the company, $3.27 per BOE, slightly escalated primarily due to the curtailed production for the quarter, but this is an improvement from the second quarter.

Next, I think it's appropriate I address Proposition 112. First, I want to thank all the PDC employees and our oil and gas industry partners for the incredible efforts behind this important campaign. Due to these efforts, we are extremely optimistic Colorado has now realized the gravity of the impacts Proposition 112 represents, not just for the oil and gas industry, but for the entire state. While we are not in the business of predicting election outcomes, based on what we understand today and the intensely focused efforts in this campaign, we are optimistic tomorrow morning we will wake up to a Proposition 112 defeat.

Now let me update everyone on the balance of '18 and our outlook for next year. In 2018, production is anticipated to be at or near the low end of our guidance range or approximately 40 million barrels of oil equivalent. This is due to the third quarter production shortfall and some recently unanticipated midstream downtime.

The liquid mix for the company should be 42% to 45% oil. Exit rate 2018, approximately 130,000 BOE per day. And in the fourth quarter, we anticipate being cash flow positive. Year-end leverage ratio for the company should be 1.4 with a liquidity of approximately $1.3 billion and a minimally drawn revolver. Lease operating expenses or lifting costs should be at or slightly above the top end of our range of $3 to $3.15 per BOE. Importantly, the company does maintain line of sight for this number to remain at the $3 level going forward.

Our commitment to you as we began 2018 was to: strengthen the balance sheet and the leverage ratio improve from 1.8 to 1.4. To grow production. We project growing production at an anticipated 25% by year-end. To pursue free cash flow and in the fourth quarter, we anticipate we will have positive cash flow for now and for many years to come, given our current plans. And to continue with our optimization in both basins, something we've been very successful at in 2018.

So now 2019. While we are just beginning the budgeting process, we anticipate fairly balanced operational and capital allocation between the Delaware Basin and the Wattenberg Field, capital spend for the company of approximately $1 billion, production growth between 25% and 35%, improving the balance sheet to an estimated 1.0 leverage ratio year-end 2019 and we are striving for free cash flow levels somewhere between $100 million and $200 million. And we anticipate sometime in the first quarter we could have a fairly significant event, a Delaware midstream monetization.

While we pursue all these significant financial and operating metrics in 2019, our marketing team will also continue to pursue flow assurance and quality netbacks in both basins. Our operating teams will drive innovation and technical and capital efficiency improvements in both basins. Our midstream group will remain point focused on working with gathering and processing providers to ensure ongoing improvements in reliability. And our stakeholder relations team will continue with its never-ending mission to educate Colorado residents around the economic benefits and safety aspects of the industry, while reinforcing the already foundational relationships we've developed with the communities where PDC operates.

With that, I will turn the call over to Scott Meyers for a financial overview of the company.

Thanks, Bart. Before jumping into the numbers, I want to quickly remind everyone that at times, I will touch on both non-GAAP non-U. S. GAAP numbers as well as our multiyear outlook. Please note that we have provided a reconciliation of our non-GAAP numbers in the appendix and our forward-looking statements at the front of the slide deck.

With that, I'll start on Slide 6 with an overview of several of our U.S. GAAP metrics for the quarter.

Total sales of $372 million represents a 60% increase compared to the third quarter of 2017 and is driven by the production increase of approximately 20% that Bart touched on as well as a 35% increase in our realized price.

One line item that I'd like to touch on is G&A expense. In the third quarter, our G&A was high at approximately $48 million, a 65% increase compared to the third quarter last year. Included in these numbers are legal-related costs of $8 million as well as increases to payroll and benefits due to increase in our headcount and our government relation costs, as highlighted in our Q.

G&A per BOE, excluding legal-related costs, was approximately $4 compared to $3.44 in the third quarter of 2017. Looking at the lower right graph, you can see 5 consecutive quarters of growth in our production, with our third quarter representing a 6% sequential growth and a 7% sequential growth in the Wattenberg.

Last, our net cash from operating activity was approximately $200 million for the quarter, representing a 33% increase from the third quarter last year and a 12% increase from the second quarter of this year.

Moving to Slide 7. The table quickly shows the strong annual growth in our adjusted cash flows and adjusted EBITDAX due largely to increased pricing and production. I will note that the graph shows the impact of our unusually high G&A expense this quarter that we just covered as both adjusted EBITDAX and adjusted cash flows are relatively flat compared to the second quarter of this year due to these legal and government relation expenses.

In terms of production costs, we saw a couple of positive trends in the third quarter, thanks in part to our Wattenberg volumes beginning to benefit from the slightly increased production capacity in the basin.

Looking at the graphs on the right-hand side of the slide, you will see that our corporate LOE per BOE as well as our total production cost per BOE decreased from the prior quarter. This is a trend we would expect to continue in the fourth quarter as we anticipate realizing strong sequential production growth in both basins.

Just a couple of quick items of note in terms of balance sheet, leverage and liquidity. First, in October, we upsized our commitment level of our borrowing base from $700 million to $1.3 billion. This results in a September 30 pro forma liquidity of $1.23 billion as we had approximately $75 million drawn on our revolver at the end of the third quarter.

As you can see, we do project to deliver free cash flow in the fourth quarter. However, we now expect to exit the year with a minimally drawn revolver as opposed to the previously expectations of it completely undrawn. This is due to our production forecast modestly decreasing, which we'll discuss more in a minute.

Next, we've updated our hedge position, including a couple of layers of incremental 2020 oil hedges that were layered on to the recent upswing in strip prices. These were largely collars with what we deem as a relatively attractive price. As you can see, the weighted average floor price of our 2020 program is approximately $60, which was the same price as our multiyear outlook we've shown in the past.

And finally as a reminder, we have no near-term debt maturities.

Shifting gears, I want to spend a little time talking about our guidance for 2018 and our outlook for the next several years. We've touched on it a few times today and in our press release issued last night, but it warrants mentioning again. Scott will give more color on this in a moment, but it's important to note we've been seeing modest relief in line pressures and as well as sequential growth in our Wattenberg volumes. However, due to the pace of system optimization from our Wattenberg third-party midstream providers and higher-than-expected line pressure despite the new plant and more system downtime than expected, our second half volumes are coming in a bit lower than originally projected.

This ultimately leads us to project our full year production volumes to come in at the bottom the end of the range or approximately 40 million BOE equivalent. This reduction in production trickles through to our BOE cost guidance as each of the metrics shown is now expected to be at or slightly above the guidance range. Importantly, this is primarily a volume issue, not a dollar issue, with the exception of our legal cost in G&A that I just touched on.

The better news relates to our price realizations, which continue to track on the favorable side of our ranges, especially for the high-valued liquid components.

We currently expect to be near or at the high end of the range for both oil and NGL, with gas also falling within the range. Of note, our Delaware Basin oil realizations for the quarter were 94%.

Finally, our guidance for the full year capital investment in crude oil and natural gas properties remains unchanged. Our run rate through the 3 quarters, tracking a little north of this range, but I'd like to remind everyone that we've idled our frac crew, as expected, in the Delaware Basin as our tun-in-line program is now complete for the year. Expect our fourth quarter to be the low-water mark for capital investment for the year.

Before turning the call over to Scott for an operational overview, I want to revisit the multiyear outlook. A quick housekeeping note, the numbers shown here are simply an outlook, which in this case, represents a steady 6-rig program, 3 rigs in each basin for '19 and '20. We are now just ticking up the formal budgeting process for the year, which we plan to release to the market in the February time frame. This is obviously a slight change to recent years and is due to our desire to better align budget announcements with the full year reserves as well as our full year actual results.

I would look for this process to be the standard process moving forward. However, you can expect us to continue providing multiyear snap charts to serve as a framework in the meantime.

As you can see on the slide, we've gone ahead and updated our 2018 column in the table to align with everything we've discussed so far. The major takeaway from this slide relates to our 2019 and 2020 outlook, which you can see remains relatively unchanged from a production growth percentage although starting at a lower-than-expected 2018 production level of approximately 40 million BOE.

Additionally, please note bullet point 4 as our outlook assumes sufficient NGL takeaway and fractionation space by our third-party providers. At this time, based on our current drill plan, we do not anticipate our year-end approved -- we anticipate our year-end approved permit. In that account, we do not currently believe the outcome of the election will have a material effect on our 2019 program or 2019 financial results. However, our 2020 outlook would require some adjustments in terms of capital allocation and full year average rig count in each basin.

Additionally, despite some headwinds this quarter, we are confident that the Wattenberg position will continue to see incremental benefits from DCP's continued investment in the field, especially in the second half of '19. Look for PDC to prioritize free cash flow generation and debt-adjusted growth metrics in 2019 and beyond.

With that, I'll turn the call over to Scott Reasoner for an operational overview.

Thanks, Scott, and good morning, everyone. Starting on Slide 13. You can see a breakdown of our activity for the quarter in each basin.

In the Wattenberg, we turned-in-line 22 wells and produced over 83,500 barrels of oil equivalent per day, which represents 7% growth over the second quarter. Considering the timing of Plant 10 coming online as well as only modest improvements in midstream line pressures thus far, this growth is a testament to our core position in the field and the ongoing efforts of our operating teams.

In the Delaware, we had 10 turn-in-lines for the quarter and smaller sequential growth than in quarters past as these turn-in-lines were predominantly in August.

Last, you can see the capital investment by basin for the quarter. As Scott touched on earlier, we project a reduced capital spend in Delaware for the fourth quarter with the planned release of our completion crew for the remainder of 2018.

On Slide 14, we provide a look at our quarterly performance for both production and LOE. We are happy that both these graphs are moving in the right direction, but again, both could have been a little better had issues outside of our control gone a little smoother. With the updated guidance commentary Scott provided, you can calculate that we'd expect to be in the neighborhood of 125,000 barrels of oil equivalent per day in the fourth quarter, while also expecting a corresponding decrease in our LOE per BOE that comes with the increased production.

Moving to Slide 15. We provide a bit more detail on our ongoing midstream initiatives, especially in the Wattenberg on the left-hand side of the slide. First, I want to focus on the blue line of the graph, which represents PDC gross operated volumes on DCP's system. You can see the steady increase in our production throughout the third quarter.

Second, the orange line shows the average line pressure at one reading point in our Kersey acreage. To be clear, this is a fair representation on the operating environment of our Kersey acreage but not necessarily of the entire DCP system. This graph highlights the strong relationship between line pressures and production volumes. I'd like to call out the circled area of the graph in mid-September through early October. This is a time frame in which we were relatively pleased with the consistent run time of DCP's midstream system. As you can see, line pressures declined, which enabled modest growth in production.

The last item to highlight on the graph occurs just to the right of the circle. It's clear that as line pressures once again climb to the levels in excess of 350 psi, due to some planned and unplanned midstream system maintenance, our production correspondingly decreased. Part of this is to be expected as DCP continues to optimize and balance their system.

With this comes a certain level of unpredictability, and it's this unpredictably, coupled with what we've seen to date, that is the primary driver in the change to our full year production expectations. Line pressures have come down more recently and production has recovered. We are hopeful that operations will stabilize throughout the winter as much of the maintenance is complete.

At the end of the day, Plant 10 represents a great addition to DCP's system, and it's unlocking incremental value each and every day.

Also highlighted on this slide is our potential midstream asset monetization process, which is progressing well. We continue to evaluate the opportunity to unlock material value for the company. Thus far, the process, which is led by Jefferies, has garnered tremendous interest. At this point, we're probably a couple of months away from giving more clarity, but stay tuned.

With all the current focus on Colorado politics and the impacts that third-party midstream infrastructure and takeaway has had on our Wattenberg production, we believe our potential Delaware Basin midstream asset monetization is currently being overlooked.

Staying with the Delaware. We're beginning to see solid initial results from our Grizzly Bear downspacing test in Block 4. You can see the schematic and location of this test, which included 6 Wolfcamp A wells on a half section, a 12-well per-section equivalent; a Wolfcamp B; and a Wolfcamp C well. So far, through about 60 days of production, we are able to draw a few conclusions, especially from our Wolfcamp As that have encouraged -- that have us encouraged.

First, and perhaps most importantly, although still very early, we are seeing minimal communication between wellbores through various choke management tests and casing pressure assessments. This leaves us pretty confident in our initial spacing assumptions of 12 Wolfcamp A wells per section in our Block 4 inventory.

Second, the production we are seeing thus far is consistent with the low GOR area of Block 4, with a very strong oil cut of between 75% and 80%. We have begun installing artificial lift to move the liquids.

Overall, production so far has been very similar to what we have seen from our peers, which is to say it's a little below a single parent well. The most important thing is we are one step closer to finding the most efficient way to develop our position, while maximizing the oil in place we're recovering all the while maintaining solid economics on a project basis.

In terms of the Wolfcamp C well, total production thus far has been a bit disappointing. We are pleased with the oil percent as this is generating approximately 60% crude. However, at this time we're trying to assess the effectiveness of our landing zone and associated completion design and their impact on productivity. The key takeaway is that we are by no means writing off the Wolfcamp C for potential economic inventory in the area, but it will require future testing. More of this is planned for 2019.

As we look into 2019, we plan to test several initiatives. First, we plan to pad drill for much of the year. We'll continue to test landing zones, varying completion designs where appropriate, along with STACK spacing tests in each of the Wolfcamp benches as well as test our first Bone Spring well. Our budget process is underway where the plans will be finalized.

Finally, shifting to our North Central Area. As we look back at our 2018 delineation program, we are very pleased with the program results thus far and progress we've achieved.

For the full year 2018, we spud a total of 13 wells and turned-in-line 10 wells in the North Central Area. Eight of our turn-in-lines to date with sufficient production resulted in an average IP rate of 200 barrels of oil equivalent per day per 1,000 feet, with 50% being oil.

The Rabbit Ears is very early in production and performing up to expectations, with around 40% crude oil, along with a strong gas production rate. As you look at the map shown and the location of our wells through the North Central position, we believe 2018 was a tremendous success in delineating this portion of the field through consistent performance again and again.

To summarize, we are very pleased with where we are in the development and delineation of our focused oily areas of the Delaware Basin and look forward to 2019, where we'll continue to build on our success.

With that, I'll turn the call back to the operator for Q&A.

(Operator Instructions) Our first question comes from Mike Kelly with Seaport Global.

Bart, let me start with the Prop 112 stuff. And I don't want to be a bad omen here, but last week, one of your competitors had to -- it was HighPoint that came out and said even if this thing went against the industry here, it might not be the end of the world for us. We'd be able to reconfigure some of our drilling units. Yes, we'd have to probably drill some shorter laterals, et cetera, but we might be able to work through it. Kind of a stark difference versus how other people have talked about it. Just curious if you guys have run a similar analysis across your acreage. And what might be the playbook if this does go the way you don't want it to go this evening?

Yes. And so I'd start with saying if 112 in the unlikely event were to pass, it would have, I would call it, fairly dramatic impacts to our ability to drill after the year 2020. So Mike, our business plan for 2019 is intact. We'll enter the year, and these are approximate numbers, but we're going to enter 2019 with approximately 200 permits in over 110 DUCs. So the capital spend and the outlook that we just gave everybody on '19, I think, might get tweaked a little bit, but fundamentally it would be in place. Then, we'd have the ultimate challenge of managing our drilling program in 2020 and beyond, of which the way Proposition 112 is written, the setback is not just from the residents, but it's a variety of different sensitive areas. When you put those on a map, that ends up having impacts, I believe, to all operators. So I've got to just speak to PDC's position on this. We would view this as a fairly, fairly significant impact to us. But again, based on what we know today, we have a lot of confidence going in tomorrow that we're going to defeat this proposition. So hopefully I answered your question.

Yes, that's great. Appreciate it, and best of luck on that. Switching over to the gas processing in the Wattenberg. And Scott, you went over on Slide 15. You can see the lines bouncing up and down on pressure. And it was great to see you guys hold the production growth rate of that 25% to 30% for 2019 in the face of this, but yes, I guess I've got to question you in terms of your confidence level, and maybe first half of '19, in how gas processing plays out in the basin before Plant 11 comes online.

I'll start, and I think Lance may throw in a couple of comments as well. When we look at 2019, I think for the first half of the year, the biggest issue will be how cold the weather is out here, and a lot of that becomes then a function of how does that impact their line pressure. If we have a cold winter, obviously, the freezes become an issue. That's one of the things I think we've taken into consideration as we've given the guidance we gave today. I would say along with that, I'd give DCP credit for the work they've done through the last 6 to 8 months preparing for this. Last year, not quite as prepared. This year, much more has been done around preparing their equipment for the colder weather and also getting additional staff to help manage these freezes and break them as we move along. So I think, again, when we look at the first half of the year, and that's really until Plant 11 gets online, we are talking about the biggest issue that we see coming at us, and I think DCP would mirror us on this, is truly that temperature of the first part of the year.

Mike, the additional comments that I'd add to that, and more in the second half of '19, is that we spend a lot of time with the management of DCP in really understanding their expansion plans out of the Wattenberg during the second half of '19 and on to '20. And from where they sit today and based upon their modeling that they do and working with us, we feel confident in the 25% to 35% growth for next year. And I think a couple of things that really drive that home for us is that, number one, we've got the Plant 11 that is scheduled in the second quarter of 2019. That's about 300 million cubic feet per day and that includes 100 million a day of bypass. Additionally, they've been doing a lot of work around securing firm transportation for takeaway for gas and for natural gas liquids as well as having the space there on the fractionalization side in both the Gulf Coast as well as Conway. So we spend a lot of time. We understand where they're headed. And although there's tightness in the market, we feel confident in our ability to deliver that 25% to 35% growth.

Our next question comes from Welles Fitzpatrick with SunTrust.

If we could just hop to, I believe, Slide 15, just so I can understand this better. I mean, should we think about it basically as, as winter rolls in and it gets a little bit cooler, DCP reworks their systems, you get back into that 300 to 350 PSI range? And then with O'Connor in 2Q, you're probably living under 300? Is that a fair way to frame up pressures in the basin going forward?

I wish I knew more about exactly where everything is going there, Welles, but it sounds reasonable, what you said. I would say the one thing that's still encouraging to me is if you look at that consistent run time period that we circled on the graph, you can see line pressures are still going down. So we don't really know yet how low they can take those pressures. That was another 2 weeks might have -- of run, might have given us an idea where that could be. I think that's still an unknown for us, and that really plays into why I am hesitant to speculate on next year. I really think that pressures will move up as we go into winter as more volumes come online. We have a significant number of wells scheduled for the fourth quarter, turn-in-lines, as I'm sure other companies do. And so that is another part that plays into this. But when you look at it overall, your assessment is probably not far wrong. The actual pressures where we land, that type of thing, there may be some variation around that.

Welles, this is Bart. I do believe that our planning meetings with DCP, and this is long term, and you're talking Plant 11, Plant 11 bypass and then Plant 12, that our goal is to continue to have sufficient processing and gathering capacity in the field, such as these line pressures, hopefully, there's some excess capacity in the basin long term to get back to what we call normal line pressures, and that is that probably an average of 200 psi, plus or minus. And that's where we were a few years ago. And whether or not Plant 11 gets us all the way there, I don't know if we've got all those models finalized yet, but I think it's going to be pretty close. I think Plant 11 is going to be a really good step towards us getting to having that sufficient capacity to really pull these line pressures down to that 200 level.

Okay. And sticking with Plant 11. Is the '19 production outlook based on Plant 11 and the second half of '19, like you guys talked about on Slide 11? Or -- and if so, I guess is that last 100 million a day just coming on a little bit later, are you guys just being a touch more conservative than the 2Q '19 DCP guidance?

No, I think we've got Plant 11. Again, we're finalizing all of our budget assumptions, but we've got Plant 11 in the second quarter of 2019. Under normal operating assumptions, we'll have a couple of months of ramp-up of that plant, so we'll probably have enhanced curtailments for a couple of months after the official plant startup. And I believe that we recognize the bypass may be a couple of months after. The bypass may not be ready, right, when Plant 11 is starting up?

Yes.

So Welles, we will incorporate all of that into our models. And our early looks, that's what we've included in the 25% to 35%.

Okay, wonderful. And if I could just sneak one last one in here. On the modified completion design in the Wattenberg, where you're getting that extra stage in the toe and one in the heel, have you guys seen enough to say that, that 10% increase of stage count will be able to move a 10% increase in the EURs?

Welles, this is Scott. We really haven't had a chance to see that yet. The line pressure is still masking all of that. I think the thing that I always point to, and we continue to do that, the thing that I always point to is the success we had as we went from 1-mile to 1.5 to 2-mile wells, and we saw the incremental reserves and production go up as we did that. And so we're leaning on that pretty hard, to continue to make that decision. But I think it's -- from my perspective, it's a good decision, and I don't think we'll be disappointed. I really think we'll see the benefits of that over time. We really just need the line pressure to get down so we can see that consistent flow from those wells.

Our next question comes from Irene Haas with Imperial Capital.

Yes. My question for you is, there's a number of things. Firstly, you have increased your borrowing base by quite a bit. Then if you kind of look at the free cash flow you're going to generate in the next few years, plus potential monetization of the Delaware Basin assets, you're going to be sitting on a lot of cash. So I'm just wanting to gauge your appetite in terms of doing an acquisition sort of outside of DJ Basin. Is that something that you would consider?

Irene, can you just state the last part of that question again?

Yes. Would you be looking to do a pretty sizable acquisition outside the DJ Basin just because, I mean, I'm looking at quite a bit of cash potentially that you guys are going to -- yes.

No. Obviously, we have tremendous liquidity. We've got free cash flow. We've got Delaware midstream monetization. We are extremely encouraged about the financial condition of the company heading into 2019. That gives us a lot of flexibility. We're not in a position here to say that's what we're going to strive to do next year. It gives us the opportunity to give strong consideration towards adding some quality inventory to our current, what we consider incredibly strong inventory in both basins. So yes, we have that. We have a lot of DUCs in Wattenberg. We'll be looking at on the capital side depending on what's happening with prices. We'll never take our eye off that free cash flow goal. And then, we get questions around stock buybacks too, and that's probably lower on the priority list right now. But, Irene, if I were to rank these, it would be inventory build; tweaks to our capital spend, which we would want some cash flow from those decisions also; and like I said, then probably stock buybacks down the list a little bit.

Our next question comes from Tim Rezvan with Oppenheimer.

In the slide deck, you highlight cumulative Delaware Basin midstream CapEx of $150 million anticipated at year-end. Is that just PDC Energy CapEx? Or does that include kind of the CapEx from the prior operator to get their systems in place?

It's an all-in number, including what we spent on the acquisition date plus the '17 and '18 capital spend.

Okay. Okay, that's some helpful context on there -- on value there. I appreciate that. And then going forward, how do you think about a sort of run rate kind of CapEx number on the midstream side? If there is a sale, will the goal be to kind of take all that off your plate and have a third-party fund that? Or do you anticipate incremental needs going forward?

Yes, this is Lance. From our perspective, we typically budget approximately that $50 million a year for our midstream capital and the Delaware Basin. And so yes, one of many options that could be an outcome in a potential midstream asset monetization would be that the capital would go away for PDC and a party that we monetize the assets to would have that capital expenditure going forward.

Our next question comes from Oliver Huang with Tudor, Pickering, Holt and company.

Just wondering, how do the spacing test on Block 4 impact or change how you all are thinking about optimal spacing configuration in other areas, specifically in the Eastern Delaware or outside of Block 4, the Central Delaware area and even potential spacing tests you all might carry out in your other zones?

This is Scott, Oliver, and I guess when we look at this overall, the data from the Grizzly is something that we're still gathering, obviously, and we're really excited about a number of other parts of that, with some of the testing that we did on that, that we'll continue to gather up. When I look at what we'll do around the field, I think we'll hold fairly consistent to that 12 wells per section equivalent in the A. And I really think that's a good number right now. If we see that as we test, because we're in that lower GOR area, we really need to move around Block 4, obviously, but also into the Central area to see what that's going to mean in those different areas. And I think that's really where our testing will stay for now. As we get more data, we could go obviously either direction from that. Our hope would obviously be always that we would move that number up, but it doesn't necessarily mean that's where we'll go. So I think at this point, we're pleased with what we're seeing. We have a lot to learn yet, and not only from the Grizzly, but all the questions that you're asking around what we do next. But at this point, we'll probably hold with that 12 wells per section.

Okay, perfect. And switching over to the DJ. Just kind of wondering, at what productive capacity as a percentage or do have an absolute number in terms of curtailment? Are your DJ volumes currently flowing at given the DCP allocation that is being still on the system currently?

I can give you a general feel for that. Really, as you can tell or if you look at the line pressure and what's going on there, a lot of things are happening as we move around. But we've been very consistent, and DCP has done a good job of making sure, I think, all of the players stay in the range that they've given us in terms of what they're expecting -- what we were producing prior to the high line pressure. And we've held fairly consistent in that and expect that to remain. So something north of 25% is really what we've talked about, and I think that still holds true. We're expecting that to hold true through Plant 11, I guess, is the best way to say it, and we'll see what happens after that.

Our next question comes from Dan McSpirit with BMO Capital Markets.

Back on 2019, how much do the lowered expectations in the DJ Basin for the second half of this year carry over into the first half of '19, potentially making for a more second half weighted growth profile in 2019? And could the second half weighting be more pronounced by the frac crew being idled in the Delaware Basin? I'm really asking for modeling purposes here.

Really, you're on a really good question. I think we're really expecting our first quarter production to be in that flattish range, with the idea exactly what you pointed to, the release of that rig crew at the end of the third quarter, beginning of fourth quarter and the Delaware plays into that fairly significantly, along with our modeling around expectations on DCP. When you move in quarter-after-quarter from there, we're really expecting it to march up incrementally is the best way to say it, and it should be reflective of, obviously, the frac crew starting in the first quarter really plays into the second quarter in Delaware and that Plant 11 in the second quarter playing into the third -- partially in the second quarter but much more in the third and fourth quarters as it gets full quarter run.

Appreciate it. And just as a follow-up here. Following up on a question -- on the acquisition question asked earlier and maybe frame it a little differently. Bart, even if Proposition 112 fails, you can't deny that the political landscape in Colorado is shifting potentially not in a good way for the industry. I have a front-row seat myself, living and working in Denver. What does this mean for the company's longer-term game plan? That is, how serious do you contemplate exiting the DJ Basin and recycling those proceeds into an operating area outside of Colorado that's perhaps more user-friendly?

Yes, and I think that's probably an extreme, Dan, of exiting the Wattenberg. We've got probably 1,300 to 1,500 locations right now to develop. And I think we've got a good tactical plan when 112 fails to continue with the education of the voters and continue to be a going concern in the state of Colorado. So I think what we want to do as a company is focus on what we know is really working well for us in Colorado, and that is our operating efficiencies, working with DCP to make sure we have capacity on the midstream. And I would classify it as small bolt-ons in these swaps, okay. And I would encourage everybody to just look for PDC to continue to pursue swaps where we can drill 2-milers, have continuous acreage blocks and have those continuous acreage blocks around communities we have tremendous relationships with. That's our goal in Colorado. As far as a significant acquisitions, yes. Would we lean towards being outside of Colorado? Absolutely. We've been out in the market. We've said if we were to do a significant inventory add, that would probably most likely be targeted outside of Colorado while we work through the political environment. And Dan, yes, I agree with you. I don't think anybody can expect Colorado to all of a sudden be this political environment to just calm down. I think what we have to expect is to continue to manage it, continue to educate, continue to communicate with the voters. If there's anything that I think is positive about this incredible campaign, the voters now have a face with this industry. You have had literally thousands of employees for the last 2.5 months wearing T-shirts, talking to people and communicating with the voters, and it has truly put a face with the industry, and I think that's a real positive. So hopefully I answered your question.

Our next question comes from David Beard with Coker & Palmer.

Just to get away from politics for a second. I know typically you've had some pretty pronounced seasonality in your production trends over the years, sequentially. I was wondering if you have some thoughts relative to the seasonality next year, just given we've got so many parts here at year-end. I wondered how that might play out next year?

This is Scott. I'll give a -- make a run with that. When we talked about that, our production being flattish in the first quarter and then incrementally higher through the year, we take into consideration that seasonality, the pace at which we're able to turn in line wells, all of that really goes into it. And I think when we look at that seasonality, it's affected in the winter by the cold and in the summer by the heat. Both of those impacting more the midstream businesses as they have to keep that equipment running in what a fairly extreme temperatures in the State of Colorado. But our teams do a really good job of modeling around that. And I think we're really set up to have that, I guess, modeled well as we move into 2019 and deal with it as we march the production up through the year. And then I think we'll be taking that into consideration as we work through that.

(Operator Instructions) Our next question comes from Eric Engle with Stifel.

Could you just expand on what you think caused the Wolfcamp C well to be below your internal expectations? And then now where does it fit into the delineation plans?

Yes, I can give that a little bit of color, I guess. When you look at what we've seen so far, obviously, it's very young. We're in an area where we like what we see in terms of the oil percentage. I think when you look at any part of this, and there's not a lot of Wolfcamp C activity in this area. So as we land the well, complete the well, all of those are challenges as well as the -- when you talk about landing zone, you're talking about rock quality. And so as we work through this, we'll be looking not only are we in the best section of the C for rock quality? And are we completing it the right way? And those types of things are something where you don't get that -- I mean, sometimes you fall into it, and you really get lucky and get it on the first well. But oftentimes, it takes hard work and testing, and that's what we're planning to continue in 2019. We definitely have -- obviously have a lot of acreage, and it gives us a lot of opportunity with the risk associated with this testing to benefit from that tremendously if we can figure this out. So we have not given up. I think we're in a really good spot to continue to work on that, and we're fortunate that as we drill As and Bs, we have an opportunity to test the C well here and there, where we can really let our teams continue to learn from the information. There is so much yet to be learned out here. We're gaining every day more information, and it's across the board, not just on the C well alone. I don't know where this will land, but I'm hopeful, yes, that we can still make the C work.

Okay, appreciate it. And then far as developing the acreage and going into development mode, how do you see the company developing the Wolfcamp A and the Wolfcamp B? Is that going to be co-developed? Or is it a situation where you're going to come back and develop the B after you develop the A?

At this point, we're still working that, but I think we would like to get into acute development, which would include the As, Bs and hopefully that includes the Cs. We're still working through that and, obviously, there's a lot of challenges that go with that, everything from how do you do it as you work through the drilling process and make sure you're able to complete the wells and get them online in a reasonable amount of time. And at the same time the size of the infrastructure, the amount of volume of water, oil and gas you're moving is fairly phenomenal if you turn those all on at once. So you have all those challenges. At this point, we're really working through that, trying to figure out the proper location of all the different wells within that section of rock and then understanding what that means in terms of how we'd go about it. I think from a general perspective, we really like getting it all or as much of it as we can at once because it does eliminate the potential for that later parent-child relationship.

(Operator Instructions) Our next question comes from John Nelson with Goldman Sachs.

I wanted to just start with, I guess, a clarification. I think earlier you were talking about the trajectory of 1Q volumes versus 4Q being flat. And I think you have exit rate guidance of about 130 MBOE a day, and the implied 4Q average, that 130 is about 3% above. So just trying to -- are we flat versus the exit rate, is there a step down from kind of the exit rate? Or any color on what we're flat from, I guess, is what I wanted to dive into.

Well, I think -- this is Scott, and I think we're still seeing some increases in our volumes in October from the Grizzly pad as well as 2 more turn-in-lines in the Delaware acreage as well as we do have approximately 50 turn-in-lines in the Wattenberg field. So I think you have more of a stabilization in November and December as you're going through, with October still seeing some climb is kind of what we're projecting.

That's helpful. I meant more for 1Q '19. The commentary that was given about it being flat versus 4Q? Or maybe I just misheard that, but I thought that's what the comment was.

Correct. It really is projected in that flattish range from 4Q to 1Q. And I think that comes down to the idea that we laid down that frac crew at the beginning of 4Q, and we really had -- as Scott was describing, we have fairly high production early in the fourth quarter this year, which leads you to the flattish production really Q-to-Q, not the peak production.

Okay, that's helpful. I just want to clarify which one that goes kind of flat off of, yes.

Right now, just to clarify, we don't have our budget finalized. We've got the final turn-in-line schedules, we've got to get them put into the budget. We've got -- we're still working with DCP and AKA to understand all of the different things they're doing. We've got freezes, so we've got curtailment factors that we're still polishing. So we've got a variety of things that need to be input, but the high level is, right now, not to expect a lot of growth in that first quarter based on where we're at. So we're probably not giving you all the detail, but I can promise you we'll have that detail when we get to our budget announcement. It would be easier because we'll be halfway through the first quarter, right?

Absolutely. And I guess as my second question, you really talked about how you think the market is missing this opportunity for a DJ Basin midstream monetization. I guess, specifically as we think about those different areas between water, kind of oil and gas, water is one that seems to kind of be gaining momentum. Are there any other different sides that you could say you guys potentially favor? And if we could then just tie back to how we could think about what's been invested maybe between each of them kind of to date?

So John, this is Lance. I don't have a specific breakout on the capital invested by sort of commodity type, if you will. What I can share is that from the process itself, there's been a lot of interest in gas, oil and water, so all 3 of those commodities. And we've got multiple participants with a lot of interest in that. So from our perspective, as we think about a potential midstream asset monetization, it more than likely includes all 3 of those. Now it could be a scenario where one company pursues both, say, gas and oil, and there's a second one that pursues the water or vice versa. I mean, there's different combinations to all of that. But from our perspective, from all that we've seen and the work that our teams have done, we feel good that all 3 of these assets are being very highly considered by the participants in the process.

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

Yes, and thank you operator, and everyone for listening in. I'd just like to thank you for your patience as we've gone through this political battle. Tonight is the night. Tomorrow, I think, we're going to wake up with a positive message around 112. And we, as always, thank you for your ongoing support of the company.

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