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Edited Transcript of PDCE earnings conference call or presentation 7-Nov-19 4:00pm GMT

Q3 2019 PDC Energy Inc Earnings Call

Denver Nov 19, 2019 (Thomson StreetEvents) -- Edited Transcript of PDC Energy Inc earnings conference call or presentation Thursday, November 7, 2019 at 4:00:00pm GMT

TEXT version of Transcript

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Corporate Participants

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* Barton R. Brookman

PDC Energy, Inc. - CEO, President & Director

* Lance A. Lauck

PDC Energy, Inc. - EVP of Corporate Development & Strategy

* Michael G. Edwards

PDC Energy, Inc. - Senior Director of IR

* R. Scott Meyers

PDC Energy, Inc. - Senior VP & CFO

* Scott J. Reasoner

PDC Energy, Inc. - Senior VP & COO

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Conference Call Participants

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* Asit Kumar Sen

BofA Merrill Lynch, Research Division - Research Analyst

* Gabriel J. Daoud

Cowen and Company, LLC, Research Division - Senior Analyst

* Welles Westfeldt Fitzpatrick

SunTrust Robinson Humphrey, Inc., Research Division - Analyst

* William Seabury Thompson

Barclays Bank PLC, Research Division - Research Analyst

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Presentation

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Operator [1]

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Good day, ladies and gentlemen, and welcome to PDC Energy's Third Quarter 2019 Conference Call. (Operator Instructions.] I would like to introduce your host for today's conference, Mike Edwards, Senior Director of Investor Relations. Sir, please begin.

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Michael G. Edwards, PDC Energy, Inc. - Senior Director of IR [2]

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Thank you. 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 a 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 at pdce.com.

I'd like to call your attention to Slide 2 of that presentation and our forward-looking statements as well as to the non-solicitation information. These communications do not constitute an offer to sell or a solicitation of an offer to buy any securities or a solicitation of any vote or approval.

In connection with the proposed SRC transaction, PDC filed with the Securities and Exchange Commission a registration statement on Form S-4. That includes a preliminary joint proxy statement of PDC and SRC that also constitutes a preliminary prospectus of PDC. This joint proxy statement/prospectus and other documents that will be filed by PDC and SRC with the Securities and Exchange Commission may be obtained free of charge at each company's website or at the SEC's website, which is sec.gov.

We will present some non-U. S. GAAP financial numbers today, so I'd also like to call your attention to the appendix slides 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 our CEO, Bart Brookman.

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Barton R. Brookman, PDC Energy, Inc. - CEO, President & Director [3]

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Thank you, Mike, and hello, everyone. A strong third quarter. Production was in line with our expectations and for PDC, the era of free cash flow generation has begun. Today we will provide several key updates: our commitment to sustained free cash flow, our improving capital efficiency and cost structure, the balance sheet strength, the successful ongoing integration process with SRC Energy.

Let me hit some third quarter highlights. The company generated free cash flow of approximately $40 million. This is on a capital investment of $165 million. The spend level is in line with our expectations, and our 2019 capital spend is now targeting at or near the low end of our updated guidance range, or $810 million. Production for the quarter, 12.7 million barrels of oil equivalent. This is in line with the company's expectations and represents a 26% improvement from the same quarter last year. Production for 2019 is firmly on target for our updated guidance range of 48 million to 50 million barrels of oil equivalent.

Operationally, we continue to make great strides. Drill times in both basins are improving, particularly in the Delaware; lifting costs are in check; completion efficiencies for the company are setting records. We spud 30 wells and turned-in-line 47. And as Scott will cover later in the call, we are making tremendous progress on our per-well costs in both basins.

From a financial perspective, we've reaffirmed our borrowing base at $1.6 billion and pro forma the SRC merger at $2.1 billion, giving the combined company ample liquidity going forward.

The leverage ratio for the quarter end at 1.5 and lifting costs were $287 per BOE, in line with our expectations. Overall, PDC's financial position is very strong as we enter 2020.

Next, let me reaffirm our commitment to generating free cash flow. As you know, we rolled out pro forma outlook for the SRC merger with $55 oil and $2.70 natural gas. And based on this pricing, in 2020 we are anticipating top-tier financial metrics, including $275 million of free cash flow. Slide 6 in the deck provides more clarity around the levers we can pull to ensure we meet our free cash flow goals.

Let's start on the left. Some of our key accomplishments in 2019 will serve as building blocks for 2020. Again, CapEx is now targeting $810 million for the full year 2019. This is the second time we've lowered our CapEx outlook for this year. Free cash flow for the second half of 2019 is anticipated to be $150 million. And during the second half of the year, we experienced per-well cost improvements in both basins.

Then moving to the far right of the slide, now pro forma SRC. Recognizing the volatility in the commodity markets, we have provided free cash flow impacts due to fluctuating oil, gas and natural gas liquid prices. During the last 2 quarters of 2019, we've seen the impacts of price volatility, and we've demonstrated our ability to adjust our operating plan. In 2020 we will maintain that same flexibility in our capital program.

The center of this slide demonstrates this optionality. First and foremost next year, we can adjust the pace of our DUC completions in the Wattenberg. Just as a reminder, we will enter 2020 with approximately 220 DUCs in the Wattenberg Basin. Secondarily, reducing our drilling pace may occur if a significant price correction happens. Be assured, as we contemplate these potential changes, we remain focused on strong, sustainable free cash flow in 2021 and for the foreseeable future.

Last on this slide and very important, since the rollout of the merger we have experienced significant improvement in our per-well cost structure. We anticipate a 5% to 10% improvement in our drilling and completion costs in 2020. This gives us even more confidence in our ability to achieve meaningful free cash flow. Again, Scott will cover this in more detail in a few moments.

Now an update on the SRC merger. First, I'd like to thank Lynn Peterson and his team for being such great partners through this process. We remain incredibly excited about the combination of PDC and SRC. We believe the future company will be a premier operator with the size, scale and financial strength to deliver long-term value to our shareholders. While we originally anticipated this deal would close at the end of 2019, due to federal regulatory approvals, which are progressing well, we now expect a January close.

Some key integration highlights. The integration team has been assembled. A full planning process is in place. We are executing on a lengthy list of key action items, and our commitment to achieve $40 million of G&A savings in 2020 is on target. We are focused on integrating the top talent from both organizations, and we've created a committee focused on corporate synergies and productivity. We have begun the process of our pro forma budget, which will be approved and announced in February of next year. We've also begun the optimization of our field operations, with a continued focus on safety and competitive lifting costs. Lastly, we maintain a strong focus on systems integration, the blending of the IT components for both companies, including the anticipated January go-live date for PDC's new ERP system.

In summary, the integration process is progressing as planned. And with that, I'll turn this call over to Scott Meyers for an update on the financials for the company.

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R. Scott Meyers, PDC Energy, Inc. - Senior VP & CFO [4]

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Thanks, Bart. Before covering the third quarter, I want to spend a moment thanking the team for all the hard work over the past couple months while recognizing the next few months are equally as important. Between the upcoming launch of our ERP system in early 2020, initial work on the new consolidated budget, integrating the systems and financials, our bank redetermination and normal day-to-day tasks, this has been a very important stretch for PDC, and your hard work is incredibly valued.

Jumping to the results for the quarter, total sales were down 17% compared to 2018 due to a 34% decrease in realized pricing, offsetting the 26% increase in production. As is the case across the sector, pricing on oil, gas and NGLs were all weak across the board compared to the third quarter of last year. PDC's realized price per BOE of just over $24 consists of year-over-year decreases of 20%, 43% and 65% for oil, gas and NGLs, respectively.

Net cash flow from operating activities were approximately $235 million, with the year-over-year increase driven primarily through changes in working capital. As you'll see in a second, our adjusted cash flows for each of third quarter of 2019 and 2018 were relatively unchanged.

Moving to Slide 10, we'll cover a few non-U. S. GAAP metrics. As a reminder, the reconciliation of these metrics can be found in the appendix. I want to quickly call out, beginning this quarter, we've had a slight tweak to our adjusted EBITDAX calculation, and we now exclude gains and losses on sales of property and equipment. A reconciliation of the past 5 quarters is also in the appendix.

For the quarter, adjusted EBITDAX and adjusted cash flow were essentially flat compared to last year, as decrease in pricing has been offset by increase in production, increase in settlement of derivatives, lower G&A and production costs. I'll point out that our per-share metrics have shown improvement as the benefit of our stock repurchases begin to take shape. More on that in a moment.

In terms of operating costs in Slide 11, I want to call your attention to the graph on the top right of the slide, where you can see the nice downward trend over the past 5 quarters. Our operating cost of $4.77 per BOE for the third quarter represents an improvement of more than 25% compared to the third quarter of 2018. Obviously, much of this benefit is due to lower prices and the associated production tax, but our LOE and TG&P are down 12% and 4% as well.

As you will see our LOE by basin at the bottom of the slide, Scott will cover more in a few slides, but we are very pleased to meet our target corporate LOE of less than $3.00 per BOE, driven by Wattenberg of approximately $2.50 and Delaware less than $4.00 per BOE. Look for PDC to continue emphasizing this, as we believe our low-cost operations are a real differentiator in today's world, where margins continue to get squeezed.

Shifting to another cost focus of PDC, Slide 12 gives an overview of the continued improvements to our G&A per BOE, which was $3.23, all in, for the quarter. Once again, we've tried to clearly show our run rate as well as our all-in G&A, which includes a variety of nonrecurring charges associated with shareholder activism, asset divestitures, PDC's reduction in force and partnership settlements.

If you recall, we lowered our annual G&A range on the second quarter to $3.00 to $3.20 per BOE, which includes all of these expenses that were incurred in the first half of the year. Since that time, we've announced the merger with SRC. That will obviously come with a variety of severance and transaction costs. If you exclude those anticipated costs in the second half of the year, we fully expect to reach the midpoint of our updated 2019 guidance range.

Most important takeaways on this slide are one, PDC remains incredibly focused on the controllable costs, both now and moving forward, as seen by the constant improvement in our run rate G&A, shown on the orange bar on the top chart. And second, we are committed to achieving our stated goals of $40 million of G&A synergies related to the SRC merger and reaching a 2020 G&A per BOE of approximately $2.00, excluding any of the transaction-related costs to the merger.

Finally, Slide 13 shows our updated balance sheet and liquidity. As Bart mentioned, PDC's standalone borrowing base was reaffirmed at $1.6 billion at our fall redetermination. Our commitment level will remain at $1.3 billion. Pro forma for the expected closing of SRC, the borrowing base has been approved at $2.1 billion with a commitment level approved up to $1.9 billion.

We feel the combination of free cash flow focus in 2020, ample liquidity and low leverage provides an incredibly strong balance sheet that serves as a true differentiator, given the macro backdrop and tightening financial markets.

Given all the talk around free cash flow and when companies expect to reach their inflection points, I want to highlight that PDC generated approximately $40 million in free cash flow in the third quarter and expects to back that up with a fourth quarter of free cash flow in excess of $100 million. These figures, combined with the returning of more than $150 million of cash to shareholders year-to-date and capital investments at the low end of the full year guidance range, highlights PDC's ability to execute and our strength as an operator. Look for more to come in 2020.

With that, I'll turn the call over to Scott Reasoner to give an overview of our operations.

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Scott J. Reasoner, PDC Energy, Inc. - Senior VP & COO [5]

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Thanks, Scott, and I want to start by echoing your appreciation for the team this past quarter. Our team has done a tremendous job at delivering well costs in each basin below our 2019 budget and 2020 outlook assumption while remaining focused on safely executing day-to-day job responsibilities amidst all the noise that a pending merger can bring.

In the terms of the quarter, total production of 138,000 barrels of oil equivalent per day represents an increase of 26% compared to the third quarter last year and a modest 1% compared to the second quarter of 2019.

In Wattenberg, we reduced our rig count from 3 to 2 late in the quarter and spud 26 wells while turning-in-line 43 wells. Wattenberg production decreased by approximately 1,500 barrels of oil equivalent per day sequentially, as we dealt with the delayed startup of Plant 11 through July and some unplanned downtime in parts of September. I'll cover this in more detail in a couple of minutes.

In Delaware we operated 2 rigs throughout the quarter and had 4 spuds and 4 turn-in-lines, all of which were in early July while growing production 10% from the second quarter to 34,500 barrels of oil equivalent per day. From a well cost perspective, we averaged $1,150 per lateral foot for our drilling, completion and facility costs in the third quarter. I'll cover this in more detail in a moment as well, but this represents a significant improvement from our budgeted expectations, with even more potential to improve heading into 2020.

Digging a little deeper on our production and LOE, you can see the strong quarterly trends in each metric on Slide 16. In terms of production, I've already covered the third quarter results, but I want to point your attention to our fourth quarter expectations. In the Delaware, we expect our fourth quarter volumes to decline around 5% to 10% compared to the third quarter. This will likely continue through the first quarter as we resume completions in the new year. In Wattenberg, we expect quarter-over-quarter growth to cover the declines in Delaware, leading to overall corporate production relatively flat to that of the third quarter. In terms of LOE, we're very happy to have the basin level Scott alluded to earlier of $2.50 per BOE in Wattenberg and sub-$4.00 per BOE in the Delaware.

On Slide 17 and 18, I want to spend a little time highlighting some of the accomplishments of our Delaware program in 2019 and looking forward to 2020. From an efficiency standpoint, our team did a great job in improving our 2019 drill times by 20% compared to 2018. You can see that this translates directly to improvements in drilling costs per lateral foot, as shown on the graphs at the bottom of the page.

In the third quarter, our turn-in-line activity was limited to our Buckskin pad in our north-central area. As you can see, these are strong wells with average peak 30-day IPs of 225 barrels of oil equivalent per 1,000 feet and nearly 50% oil. Importantly, these wells came in at $1,150 per lateral foot.

For the quarter, we're very proud that our average well costs have come in between $200,000 to $800,000 below budget, depending on lateral length. As we begin working with our service providers and determining our 2020 budget, we hope to not only maintain these efficiencies we've gained this year but continue improving from both a time and cost perspective. Early indications are showing potential for 10% to 15% improvements from 2019 budgeted D&C costs, which equates to $1 million to $1.5 million per well. As a reminder, our 2020 outlook assumes flat well costs year-over-year with 25 to 30 spuds and turn-in-lines focused entirely in our Block 4 area.

Shifting gears to the Wattenberg on Slide 19, I want to spend a few minutes discussing the operating environment, specifically highlighting pressures experienced in the third quarter and early parts of the fourth quarter and the resultant impacts on our oil volumes. As you can see on the chart at the bottom left of the page, there's a clear relationship to lower line pressures and improved productivity. In the early part of the third quarter, which is shown in the gray box, you can see line pressure spike up and remain high until Plant 11 comes online. In the same time period, PDC's volumes, in the dark blue line, decreased in conjunction with the high line pressures before increasing as Plant 11 comes online. You can see the same relationship again in the third quarter as DCP underwent some unplanned downtime.

When it comes to oil production, this relationship is even more magnified, as data on a pad-by-pad basis clearly demonstrates increasing GORs at periods of high line pressure spikes. The good news is that recent performance, mainly through October and thus far in November, has seen line pressures decrease to levels below 300 psi in certain parts of the field. Even on the graph, you can see a very clear downward trend in line pressures since Plant 11 came online, aside from the unplanned downtime. With continued improvements, we would expect to see an uptick in our overall and oil performance in the fourth quarter.

On the right-hand side of the slide is a reminder of the gas infrastructure improvements that are well underway. All of this work is necessary for DCP to increase, by midyear next year, their capacity to 1.7 Bcf or by about 30% from current capacity.

Last, I want to give you an overview on the current CDPHE study and what it means for PDC. As you all are aware, the CDPHE used 2013 to 2016 air sampling data to model and predict the potential health impacts to hypothetical communities within 2,000 feet of an oil and gas well. The study found no long-term health risks associated with exposure to the development or production phases of our operations. However, certain worst-case weather and emissions scenarios did show potential for adverse short-term health effects. Both the CDPHE and COGCC agree the model has limitations, and additional measurement with documentation of specific operating conditions is needed.

PDC and the industry look forward to the opportunity to work together to gather site-specific and update current best management practices, or BMPs. While the additional data is being gathered, updated BMPs will be required, and permits will be scrutinized where there are building units within 2,000 feet compared to the current distance of 1,500 feet.

Additionally, both PDC and SRC have our 2020 drilling plan covered by already-approved permits. In terms of PDC, we expect to exit 2019 with approximately 150 DUCs. That number is closer to 220 on a pro forma basis combined with SRC. The result of this is our activity for the next 2 years can be categorized as DUCs and existing approved permits. Although this will add work to our existing permitting process, we believe that we will be able to work with the COGCC to obtain permits that will allow us to continue to operate in a safe manner.

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

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Questions and Answers

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Operator [1]

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[Operator Instructions.] Your first question comes from the line of Gabe Daoud from Cowen.

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Gabriel J. Daoud, Cowen and Company, LLC, Research Division - Senior Analyst [2]

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I was hoping maybe we could just start with any clarification on 4Q and just maybe a sense of what the oil mix could look like in the quarter. I know you're guiding BOE flat sequentially, and the full year guide does remain unchanged. But curious what you think this means for corporate oil potentially growing in 4Q.

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Barton R. Brookman, PDC Energy, Inc. - CEO, President & Director [3]

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That is a question that a tremendous amount of that is dependent, obviously, on the PDC -- or I'm sorry -- the DCP run time. We've got to make sure that their equipment runs well. If that happens, we obviously see from our existing wells the idea that we should continue to see oil growth. And with that, particularly we're hoping that the line pressure comes down in the northwest part of the field where our lowest GOR wells are, and that's where we'll get the most benefit. In terms of where we're headed, we're still talking about that 40% range as really what we're looking at for oil for the year on an overall basis, on a corporate basis.

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Gabriel J. Daoud, Cowen and Company, LLC, Research Division - Senior Analyst [4]

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Got it. Thanks, Bart. And then just as a follow-up, as we're looking into 2020, obviously some great efficiencies realized and well costs lower in both basins. And you did hit on this, with the budget assuming flat well costs year-over-year. But how do you think about the initial target or high-level budget you laid out at the time of the acquisition of $1.2 billion to $1.4 billion, and then also how you're thinking about growth at this point and if you think the program could be a bit more back-end weighted overall as we await more DCP capacity in the Cheyenne Connector coming in service.

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Barton R. Brookman, PDC Energy, Inc. - CEO, President & Director [5]

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Gabe, let me start. We rolled out $1.2 billion to $1.4 billion with a midpoint of $1.3 billion on the pro forma outlook. Clearly, we're leaning towards the lower end of that right now, based on the management of the DUCs that I talked about and the cost improvements that we're seeing. And I think we even have an opportunity -- and I've got be careful here because we're still right in the middle of our budgeting process -- but I think we have an opportunity to even move below the lower end of that as we go through the budget.

Most importantly, I think recognize, depending on where pricing is, the levers I referred to in my opening, we can pull those to move that number, and in some cases, move it substantially. And again, expecting February for us to roll all of this out in our final approved budget.

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Operator [6]

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Your next an comes from the line of Asit Sen from Bank of America Merrill Lynch.

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Asit Kumar Sen, BofA Merrill Lynch, Research Division - Research Analyst [7]

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On just following up on the oil cut, and you've given out fairly precise guidance for 2020. Given shifting Delaware in-line pressure issues, could you broadly speak to the cadence of oil cut as we move through 2020 and perhaps as we look beyond 2020? How should we think about it?

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Scott J. Reasoner, PDC Energy, Inc. - Senior VP & COO [8]

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Yes, I'll take a run at this and then maybe somebody else will jump in and hit on some of the topics I don't hit.

When you look at where we're at right now, we're -- and this is -- I'll talk about PDC alone and then talk a bit about adding in SRC. We don't have any frac crews running right now, so we're expecting production in the first quarter to dip, and I think that's a fair look when you think about not having any turn-in-lines, really, in the fourth quarter. I think we had a few early, but basically, through the fourth quarter, we've not turned any wells online and won't through the rest of the year.

We'll starting fracking again in the first quarter, and that should bring an uplift in the second quarter and the third quarter. And then depending on how quickly those wells get completed that we're planning on completion and keeping a real solid eye on our capital spend, we may have to slow down at the end of the year again, depending on circumstances such that we stay within our capital budget. But that could flatten out fourth quarter. I think we're still talking in that 40% to 42% range in terms of oil overall for the year, and the upside to that is the Delaware, where we look at the work that we're going to be doing there is on the east side of Block 4 through the central part of it in terms of turn-in-lines, and we expect that GOR to be a bit lower and therefore give us a little bit more oil relative to gas.

And then I'll add to that the SRC side. They are running a frac crew right now, and that will help us a little bit flatten out that first quarter. And then the idea that they're a little bit oilier than us just in general, and the Wattenberg also pushes that oil up just a little bit. But still, in that -- I think we're still comfortable in that 40% to 42% range.

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Asit Kumar Sen, BofA Merrill Lynch, Research Division - Research Analyst [9]

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Appreciate that rundown, Scott. And just following up on that, entering 2020 with the DUC count at 220, where should we exit next year, given -- I appreciate that you're in the midst of your budgeting process -- but how should we think about the DUC count?

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R. Scott Meyers, PDC Energy, Inc. - Senior VP & CFO [10]

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Yes, I think we'll be working our DUC count down throughout the year. We obviously haven't finished our final budget, but I think we gave a range of reducing that DUC count 75 to 100 throughout the year, through 2020, as we manage through the completion process. But we're still putting the budget together, as Bart alluded to earlier. But I definitely think you'll see that DUC count come south.

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Operator [11]

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Your next question comes from the line of Welles Fitzpatrick from SunTrust.

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Welles Westfeldt Fitzpatrick, SunTrust Robinson Humphrey, Inc., Research Division - Analyst [12]

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Can you talk about the 220, the DUCs that you'll have going into 2020? What do you consider the normal run rate? Where would you envision that going to by year-end '20? And I know it's in flux, but presumably those would be at the front of the line.

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Barton R. Brookman, PDC Energy, Inc. - CEO, President & Director [13]

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Yes, I'll make a little run at this. I think, when we look at the 220, that's more than we need. And as Meyers was talking about, we're going to be using up some of those this year.

When you talk about a minimum, that's going to grow and shrink dependent on how many rigs you have running. But with 3 rigs, we probably have somewhere in the neighborhood of 100 is probably a pretty close minimum. And I say that you may drop down into the upper teen -- 70, 80, 90 at one point. But in order to stay ahead of the -- with the drilling rigs, you don't want to get right up against those as we're completing wells. That feels comfortable to me.

It also depends on where those rigs are running. When they're running in separate areas, you obviously need a little bit more room between each of those rigs and the completion crews. But that's part of the project that we're figuring out. But as far as a minimum, something in that 100 range. So we could pull it down another 40 or something under ideal circumstances if you looked at beyond the end of 2020 and going into 2021. We haven't decided whether we're going to do that, Welles. I want to make sure that's clear. That's still part of our budgeting process in looking at 2020.

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R. Scott Meyers, PDC Energy, Inc. - Senior VP & CFO [14]

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And Welles, I think our completion pace right now, and we're working through all this and we're considering DCP line pressures, startup of some of their key projects, availability of services. But right now -- and Scott, correct me if I mess this up -- but I think we're looking at like 1.75 equivalent frac fleets to 2 frac fleets to...

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Scott J. Reasoner, PDC Energy, Inc. - Senior VP & COO [15]

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In the Wattenberg.

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R. Scott Meyers, PDC Energy, Inc. - Senior VP & CFO [16]

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In the Wattenberg to, A, reduce the DUC count, and B, keep up with the 3 drilling rigs. So you can expect that kind of frac cadence as we go through the year.

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Barton R. Brookman, PDC Energy, Inc. - CEO, President & Director [17]

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Probably start both of them again, without knowing for sure, but we'll probably start both of them up at the beginning of the year and 1 in Delaware as well.

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Welles Westfeldt Fitzpatrick, SunTrust Robinson Humphrey, Inc., Research Division - Analyst [18]

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Okay, perfect. No, that's very helpful. And then on -- you guys mentioned in the presentation that fracks in White Cliffs were taking line volumes. Have you seen -- has that led to any NGL improvement, pricing-wise, in the basin yet, or too early?

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Lance A. Lauck, PDC Energy, Inc. - EVP of Corporate Development & Strategy [19]

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Welles, it's Lance. Yes, we do anticipate some strengthening in NGL pricing because both those 2 pipes go to Mont Belvieu and they have a premium price there versus out of Conway. So yes, beginning here in the fourth quarter, there will be some strengthening, we believe, in the NGL price versus out of the third quarter.

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Welles Westfeldt Fitzpatrick, SunTrust Robinson Humphrey, Inc., Research Division - Analyst [20]

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Okay, perfect. And then just one last one, if I could sneak it in. It seems like the COGCC white paper that they put out less than a week ago, it seems pretty innocuous, maybe even positive post the CBPHE, that it's just what they said they were going to do. And I'm not trying to lead the witness here. I just wanted to get you-all's thoughts on that white paper they put out and how that shapes up versus you-all's expectations.

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Scott J. Reasoner, PDC Energy, Inc. - Senior VP & COO [21]

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This is Scott, Welles, and we obviously have a team that's looking at that very carefully. I've read it one time through, but there's a lot in there, as you probably recognized. Part of that is we feel somewhat the same way, but won't know -- I say, “somewhat” because we won't know until the rules are actually written. Much of this we expected, but again, it comes down to the final, when they put the final period at the end of those rules. And it's a fairly substantial group of rules. That's when we'll really know.

Our team is working tremendously hard, though, to understand what's in there, but more importantly, what we can do to work with the COGCC to make sure that it ends up being something that we can work with in the Wattenberg.

And I will tell you it's not just us alone, obviously. It's the industry that we're working with as well.

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Operator [22]

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[Operator Instructions.] Your next question comes from the line of Will Thompson from Barclays.

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William Seabury Thompson, Barclays Bank PLC, Research Division - Research Analyst [23]

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You noted line of sight to $1 million to $1.5 million savings on the Delaware wells, and you captured about, I think, $100,000 to $200,000 savings on the recent Wattenberg wells. So my math would imply that you at least have $60 million of savings going into 2020. Just to be clear, do you see efficiencies versus what was baked into the CapEx guide upside to the 2020 free cash flow guide, or more likely an offset to maybe a lower PDP base going into 2020 and some of the recent price realization headwinds?

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R. Scott Meyers, PDC Energy, Inc. - Senior VP & CFO [24]

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No, I think it goes back to what Bart alluded to earlier. When we're looking right now, when we came out with our 2020 outlook of $1.2 billion to $1.4 billion, that was based on the current pricing that we were experiencing at the time. And as Scott alluded to, we're seeing some downward pressure on that pricing, which would lead to a positive near the low end of that range or maybe even below that range. That's not really anticipating any change in our activity level, although as we go through this process, we are still looking at that as a team, and we'll assess that as we go through. That's why we have the range out there. But I would say when you're referring to those well costs, those were not baked in, and that will move our range south. We just have to finish the rig cadence and the pace to determine what we think is the best to make sure we generate a free cash flow for next year, 2020. That's our #1 target that we're looking at when trying to determine all of our metrics.

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William Seabury Thompson, Barclays Bank PLC, Research Division - Research Analyst [25]

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Okay, and I appreciate the price sensitivity stats on Slide 6. Can you remind us what is roughly the baseline realization? Do you assume the free cash flow guide? And to piggyback on Welles' question, how do you think about NGL and gas realization progression as new gas processing capacity and takeaway capacity comes online?

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Barton R. Brookman, PDC Energy, Inc. - CEO, President & Director [26]

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I'll start with that and Lance, I'll let you chime in. I think for oil, we are in the 90% to 95% realization; natural gas, 40% to 50% realization; and NGLs, 20% to 25% was the range when we came out with the $2.75. Clearly in the third quarter, we had some pressure on those realizations. I think right now when we're looking towards 2020, we anticipate something below -- or something between what we experienced in the third quarter and what we had our outlook at last -- in August. We are seeing some relief coming, and you can already see some of the uptick in the prices right now. Lance, any other comments on that when you look at 2020 right now?

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Lance A. Lauck, PDC Energy, Inc. - EVP of Corporate Development & Strategy [27]

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I'd just say on the NGL side, when you look at third quarter, we feel like this was a low shoulder month pricing, just the supply and demand of NGLs. I think as we get more barrels going to Mont Belvieu, that will be helpful. As we get into the winter season here, there will be more utilization, obviously, of propanes across the country for heating, so those will be both positive things for us. So as we look into next year, we see some strengthening, clearly past the 15% realization of NGLs that we had in the third quarter. It's going to be a function, again, of the supply and demand and all the different utilizations. But we think we're in a good spot for improvement, clearly, over the third quarter of what we see presently.

As far as the gas side, you've seen some strengthening in the near-term gas prices. There's been a lot of continued utilization of gas for some of the winter here, just early in some of the various areas of the country, so that's been a positive. But that's something we'll continue to monitor going forward. And that's why we've got those adjustments on one of the slides there, Will, so you can go back and see what are the differences in calculations on free cash flow based upon the different ranges of commodity prices that could be presented to us next year.

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Operator [28]

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I'm showing no further question at this time. I would now like to turn the conference back to Mr. Bart Brookman.

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Barton R. Brookman, PDC Energy, Inc. - CEO, President & Director [29]

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Thank you, Sarah, and thank you, everyone, for joining. And just as closing, we couldn't be more excited how we're wrapping up this year. Again, thank you to Lynn Peterson and his team. The merger's progressing, and we feel great about that, and we're super excited about our outlook for 2020.

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Operator [30]

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Ladies and gentlemen, this concludes today's conference. Thank you for your participation and have a wonderful day. You may all disconnect.