PDC Energy Inc (PDCE) 2020 Q3 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the PDC Energy Third Quarter 2020 Earnings Conference Call. (Operator Instructions)

As a reminder, this conference is being recorded. I would now like to turn the conference over to your host, Kyle Sourk, Investor Relations. You may begin.

Thank you, and good morning. On today's call, we have President and CEO, Bart Brookman; executive Vice President, Lance Lauck; Chief Financial Officer, Scott Meyers; and Senior Vice President of Operations, Dave Lillo. Yesterday afternoon, we issued our press release and posted a presentation that accompanies our remarks today. We also filed our Form 10-Q. The press release and presentation are available on the Investor Relations page of our website, www.pdce.com.

On today's call, we will reference both forward-looking statements and non-U.S. GAAP financial measures. The appropriate disclosures and reconciliations can be found in our presentation. Additionally, we've modified our terminology from free cash flow to adjusted free cash flow. The definition and formula remain unchanged from prior disclosures. With that, I'll turn the call over to our CEO, Bart Brookman.

Thank you, Kyle, and hello, everyone. Let me begin this call with some numbers for the third quarter and our revised outlook for the year 2020 and 2021. I encourage you to study these results as I believe they demonstrate the strength of the company and the tremendous value PDC presents.

For the quarter, $225 million of free cash flow. It's approximately 20% of the company's current market capitalization. Debt for the quarter was reduced by approximately $215 million and a leverage ratio quarter ending of 1.7. Production, 17.7 million barrels of oil equivalent, well above our expectations. And a cost structure, a result of both the SRC merger and our intense focus in this area, $4 per BOE that is combined LOE and G&A, a record for the company. And for PDC's revised outlook, 2020 annualized free cash flow is anticipated to exceed $350 million.

Going forward, you can expect quarter-after-quarter pursuit of free cash flow. And next year, we anticipate approximately $300 million of free cash flow at $40 oil. This calculates to a yield based on the enterprise value of the company, over 10%, top-tier amongst our peers. In the near future, we believe our total debt level will be reduced below $1.5 billion. And our long-term goal remains to drive our leverage ratio to the 1.0 level, which we consider the gold standard for today's industry. Now let me cover a few key themes I'd like you to take from the call today. First, sustainability of our capital programs, particularly in the state of Colorado.

Later in the call, Dave Lillo will review our turn-in-line schedule that is virtually assured, well into 2024, with over 475 combined DUCs and approved permits in hand. We've obtained 32 permits over the last 2 months, and we remain very confident this will continue under the recent modifications to the approval process at the state of Colorado.

Second theme, improvements to our capital efficiency and the tremendous positive strides our operating teams have made in both basins. We expect a 5% to 10% improvement in our per well cost as we finalize our 2021 budget, helping us drive continued quality drilling returns in the Wattenberg and Delaware. Third theme, the financial focus I've already touched upon. Balance sheet strength as we strive for long-term 1.0 leverage ratio, consistent and sustainable free cash flow and intense cost management. And the last thing, expect modest production growth of up to 10%, while we continue to obtain permits, drive quality drilling returns and deliver the outstanding financial metrics I have outlined. So in closing, let me thank all of the PDC employees.

During this pandemic, we have experienced demand destruction, incredible commodity price volatility and overhaul to our work environment, including extra health protocols and working remotely. You have demonstrated the commitment and resolve to help PDC remain strong, resilient and focused during this uncertainty. Again, I thank you. With that, I'm going to turn the call over to Dave Lillo for an operational update.

Thanks, Bart. Before I begin, I'd like to take a moment to thank the team for their tremendous effort in the recent months. Our planning and development, regulatory, permitting and land groups have worked tirelessly, collectively to ensure PDC is well positioned both now and the future. Moving to the third quarter, Slide 7. We invested approximately $35 million to run 1 Wattenberg drilling rig for 3 months, while resuming Wattenberg completions in September. Due to the lack of new turn-in-lines in the basin and as we articulated in our last call, both production and oil production were relatively flat on a sequential basis compared to the second quarter. More specifically, total production of 192,000 BOE per day represented an increase of 3% from the second quarter, while oil production of 65,000 barrels per day was a decrease of 4%.

The discrepancy lies between the movement in total production, and oil production is primarily related to late second quarter activity in each basin. In Wattenberg, we returned to production previously curtailed higher GOR wells that offset quarter-over-quarter growth in the Delaware, which was driven by late second quarter turn-in-lines.

Finally, from an LOE standpoint, I'm extremely proud of our results for the quarter of just over $2 per BOE. In Wattenberg, our team has done a great job of optimizing the size and utilization of our compression fleet and renegotiating contracts while effectively managing the staff, and realizing the benefits of consistently lower line pressures.

In Delaware, we have converted several locations to the power grid and eliminated the need for electrical generation. We're very excited about our trend in our LOE the last quarters, but are keeping a close eye on our cost as there is potential for some of these savings to erode in 2021 due to the changing Colorado regulatory backdrop.

Slide 8 takes us to a look at Wattenberg drilling and completion efficiencies that we have realized through 2020. Beginning at the top of the slide, you can see a 10% improvement and the number of hours per day spent pumping compared to the first quarter of 2019. Simply put, if nonproductive time is reduced, our team is completing and not swapping equipment and dealing with minor maintenance. There is a direct correlation in the number of stages per day and ultimately, dollars per well. Recently, our Wattenberg team has reached levels of safely completing an amazing 20-plus stages per day. From a drilling standpoint, the story is much the same. The spud-to-spud drill times for our Wattenberg XRLs are down to an average of 6 days in 2020.

This is an improvement of 20% compared to only a year ago. These efficiencies as well as cost concessions in each basin give us the confidence that our 2021 wells -- well costs could improve by 5% to 10% from the current messaging of $400 a foot in Wattenberg and $800 a foot in Delaware for drilling, completions and facilities. Again and this is very important, we just started to formalize our 2021 budget process, and we'll be evaluating the implications of faster drilling and completions with lower well costs.

In an ideal world, we would like to avoid frac holidays and lumpiness in our development program, but are committed to prioritizing sustainable free cash flow with little emphasis on production growth.

Next, on Slide 9. I want to spend a few moments going over our continually improving permit story in Colorado. If you recall, our previous disclosure estimated that PDC would exit 2020 with approximately 200 approved permits compared to our current estimate of approximately 275. This is an increase of equivalent to a full year of drilling with 1 rig. As Bart mentioned, we now project to exit the year with 475 combined permits and DUCs or approximately 4 years of future turn-in-line activity at our current 1 rig pace. Over the course of the third quarter, our team was able to secure a number of additional surface locations or Form 2As well as individual permits or Form 2s.

There are a couple of important takeaways here. First, 32 well permits were approved in September and October. During and immediately after the initial rule-making sessions. This is a strong indicator that PDC's permit process is directly in line in what we believe the COGCC will require moving forward. Second, business density and proximity. As we show in the middle of the slide, the 4 surface locations associated with the 32 well permits had an average of 10 business units -- I'm sorry, building units within 2,000 feet and an average distance to the nearest BU of less than 1,000 feet. I know this is tough to visualize, but less than 10 building units within a radius of nearly 0.5 mile is representative of our rural nature of our position.

Finally, our team is hopeful that we will receive additional permits between now and the end of the year, which will further increase our projected year-end counts to north of 500 combined and secure our turn-in-line activity into 2025 at the current pace.

Moving to Slide 10. We provide a comparison of our permitted and unpermitted surface locations. First, it's very important we don't overlook the most important factor of our position. We are 100% located within Weld County, Colorado. Much of the story becomes extremely challenged if that were not the case. Next, it is critical that you keep in mind that none of these future locations have gone through potential surface, pad optimization or alternative site analysis that could favorably change some of the stats.

Finally, our permitting strategy moving forward is focused on taking advantage of our contiguous acreage, positioned by several surface locations together to form oil and gas development plans or OGDPs and comprehensive area plans or CAPs. This is aligned with the COGCC stated desire for operators to take advantage of the long-term approach to planning and development in our state.

I won't go through all the data on this slide. But you can see we've provided a look of our permitted and unpermitted locations in terms of both building unit density and proximity to the nearest building unit or BU. We feel these measures are important as they characterize our ability to either gain unanimous consent or demonstrate equivalent protections in the COGCC hearing process.

Our intent on Slides 8 or 9 and 10 is to paint a very clear picture, the combination of our best management practices, our community relationships, our rural acreage position, entirely in Weld County, positions PDC for successful partnership with the COGCC. We have tremendous confidence in our long-term Wattenberg development plan.

With that, I would like to turn it over to Scott Meyers, Chief Financial Officer.

Thanks, Dave. As we've highlighted so far, the third quarter featured tremendous results that we're very proud of. But before we review the financials in more detail, I want to extend my deepest gratitude to the entire accounting department, especially those located in our West Virginia office. For years you have demonstrated extreme professionalism and proficiency. Over the past several months, these traits and more were once again on display, as you ensured we made a smooth transition to our centralized location in Denver. We're excited to welcome the new hires and know they will continue with the high standards that you've established. Again, thank you.

As a reminder, our non-GAAP reconciliations for figures shown on Slide 12 can be found in our appendix. On the left-hand side of the slide, provides an overview of a number of key financial results for the quarter, but I want to take a minute and focus on the 2 graphs on the right. First, our G&A. For the third quarter, our cash and noncash G&A came in at $32 million or $1.84 per BOE compared to $41 million and $3.23 per BOE in the third quarter of 2019. This represents an improvement of more than 40% and is a very clear sign of the positive benefits that we're realizing from our SRC merger.

Importantly, the lack of nonrecurring light blue bar on the graph indicates we've more or less reached our run rate G&A. As we continue to work through our 2021 budgeting process expect PDC to meet or improve on these already impressive numbers. Next, adjusted free cash flow. Over the past 5 quarters, PDC have delivered a staggering $440 million of adjusted free cash flow. This includes all deal costs and integration costs and they do not include our $82 million of proceeds from our midstream Delaware divestiture.

Amidst all the uncertainty in commodity prices and politics and the industry in general these results highlight our asset quality, overall team performance at managing costs and are proof that our commitment to capital discipline and focus on execution is paying off.

Moving to Slide 13, we provide an overview of our balance sheet and hedge position. Last week, we completed our fall redetermination of our credit facility resulting in a borrowing base and commitment level of $1.6 billion. In the quarter, we successfully paid down $215 million of total debt through our free cash flow. When considering our small tack-on bond yield in September, you can see we have borrowings of $285 million on our revolver and liquidity of $1.4 billion as of September 30.

It's also worth noting that in October alone, we paid down an additional $70 million of debt. PDC has a clear stated goal of utilizing free cash flow to reduce total debt to a level of $1.5 billion. In a cyclical industry with commodity price volatility, our view like many others, is a clean balance sheet with low debt is the first step before initiating sustainable shareholder-friendly initiatives. Moving to our guidance and our outlook. We first cover our 2020 projections on Slide 14. The biggest adjustment is our increase to projected adjusted free cash flow for the year, now north of $350 million compared to prior guidance of approximately $300 million. Much of this increase is due to maintaining our capital discipline while improving our cost structure and differential. We now assumed $2.50 gas and $10 NGL realizations compared to the prior guidance of $2 gas and $9 NGLs, while our oil assumption remains at $35 a barrel. From an operational perspective, we still project running 1 rig and 1 crew in the DJ with minimal Delaware activity through year-end.

This should result in capital investments of approximately $110 million for the fourth quarter. It's worth noting that our anticipated quarterly average exit rate for oil is unchanged at 60,000 barrels per day. On a BOE basis, we now expect 175,000 barrels or BOE per day compared to prior guidance of $170 million.

Both of these represent decreases from the third quarter, less than 10%, which is relatively consistent with our prior guidance. Finally, before opening the call to Q&A, I want to cover our 2-year outlook. As Dave mentioned, we're in the early stages of our annual budgeting process and our 2021 numbers are still an outlook at this point. But seeing how we're really just talking the next 5 quarters, the team is getting really dialed in.

There are a couple of highlights worth mentioning on this slide. First, in addition to increasing our 2020 free cash flow, we've also increased our 2021 free cash flow projection from $250 million to $300 million. Each of these adjusted free cash flow figures represents not only an extremely impressive free cash flow yield, but a free cash flow to enterprise value of 10% or more. From the third quarter '19 through 2021, we now project to generate approximately $850 million of free cash flow on essentially a $40 deck. Additionally, we've generated free cash flow in 4 of the past 5 quarters and over the next 5 quarters, we project to generate more than $400 million of additional free cash flow and approximately $650 million of capital investment, which brings me to my second point, our reinvestment rate.

The guidance and outlook that you see in 2020 and 2021, each reflect a reinvestment rate below 70% at $40 oil. As I said earlier, our current focus is exclusively on debt reduction, but our strategy is quickly positioning us for a multifaceted approach to meaningful capital returns to shareholders in this low price world. These numbers across the board can compete toe-to-toe with any company in the sector. This is a direct testament to the quality of our team and our assets.

At PDC, we have a track record of execution. At year-end, we expect to have 4 years of Wattenberg turn-in-lines in hand, and we're focused on achieving this plan for years to come.

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

(Operator Instructions)

We have a question coming from the line of Brian Downey of Citigroup.

Bart, with the healthy free cash flow, as you noted, debt levels are now down below $1.7 billion at the end of October. And you've laid out a path of continued material free cash flow into 2021. That should put your $1.5 billion debt target that you talked about last quarter clearly in sight. How are you thinking about timing in the preferred menu of options for shareholder returns once you get down to those debt levels?

Yes. Let me start, and I'll flip this over to Scott. But our first goal is to get to the $1.5 billion level and then work with the Board on our options. At the current stock price, I would say our share repurchase program would be reinitiated, and that would be our first priority. And then obviously, you have the dividend discussion out there, which I think we would start on the share repurchase side as our first step, obviously, keeping an eye on our stock price and then always have those discussions around dividends, but wouldn't make a commitment on that right now. Scott, do you want to add to that?

No, I think that's really good, Bart. And just remember, it's going to be a dual-facet approach. We're going to continue to pay down debt as well. Because our overall debt goal is to get us to a 1.0 leverage ratio as well. So I agree with 100% of everything you just said, Bart. So thanks.

Great. And then as a follow-up on the Colorado front, the 32 additional location permits that you received during September and October. You noted in the deck, the average proximity to the nearest building unit was 750 feet. Based on what we know so far, could you characterize once the new mission change rulemaking goes into effect next year? How do you anticipate that permitting process to play out versus the permits you just received? Do you anticipate a similar experience or any additional regulatory hurdles in the permitting process come January?

So this is Dave Lillo. I'll take that one. I think what we have is the permits that came in, in the last recent months have gone through a -- what they call in a director's objective criteria. Those were temporary guidelines put in place until the final rules are in place. We've worked extremely hard with the oil and gas commission, hand-in-hand to come up with the new rules. And what can be done to best protect environments and building unit locations. We feel very confident in going forward to meet the same criteria as the new rules are -- that are coming out here in -- the final wording is on November 20.

And really, the criteria is that no oil and gas location in a working pad can be located between 500 and 2,000 from a building unit, unless one more of the following criteria is satisfied. And that's getting consent or going through an oil and gas development plan or a CAP or all your equipments out to site 2,000 feet or you show equivalent protections that protect the environment.

Going through the new rules, as we see them today, we'll first go through a surface use agreement with the landowners. We'll notify the business -- the BU owners within 2,000 feet. We'll go through the local review with the government, with the local community, which at this point is a local process, which we will continue to do to get their approval.

And then at that point, you submit a 2A to the Julie Murphy, COGC staff. Once you get the recommendation, it will go to a hearing where we will go in front of the professional permanent commission. And at that point, we should be able to influence getting our permits based on our best management practices and everything that we've been doing up to this point. I know, that was a lengthy...

Brian, I think Dave did a great job of showing he's got an incredible knowledge of what's going on. Let me just take a simplified spin on it. We have all the confidence. We've got great knowledge of the new rules. The answer is yes. Some of the criteria for those permits we received is similar to the technical initiatives and best practices we're going to have to show the commissions. If we don't get the BU owner's consent on the drilling, we have a lot of confidence that we'll just -- we will be getting consent. We have the utmost confidence in the communities and the county. And I think the last component of this is we have the OGDP process and the CAP process that Dave touched upon, those are both new areas that will give us other avenues to obtain permits in larger quantities, actually.

So again, a lot of new things here. But overall, we have confidence because the practices, technical and operational practices we have had in the past are similar to what the commission is looking for in the future, and we will continue to implement those and our operating reputation in the state of Colorado and with the commission is so favorable. We have a lot of confidence in this.

Our next question comes from the line of Umang Choudhary of Goldman Sachs.

Wanted to follow up on the free cash flow priorities. You mentioned priority to use the free cash flow is towards debt reduction and return of cash to shareholders. In the past, you had also mentioned the benefit of greater scale in your Delaware operations. What are your thoughts on using free cash flow towards M&A, especially given recent proposed rule changes in Colorado and recent consolidation in the industry?

Additional scale right now in asset acquisitions would be a lower priority. Our priorities right now are ongoing execution. As I noted quarter after quarter, debt reduction below the $1.5 billion. And then as Scott Meyers noted continued improvements in the balance sheet while we give consideration to return to shareholders.

Great. And my follow-up is on 2021 spending plans. You're potentially contemplating completing more wells in 2021 at the same budget due to cost savings. Philosophically, what are you looking at that can drive your decision towards more activity versus generating more free cash flow? Is it efficiencies from consistent operations or your views on the macro? And how do you balance it with potential permits and how that process plays out next year?

Yes. I mean that's a great question. And that's the whole thesis of our budgeting argument. How do we go through this. And number one is free cash flow. And that's what we're going to drive to make sure that. As we said today, I'm very confident in a $40 world having over $300 million. We also, besides just being able to generate free cash flow, it's really important to have operational efficiencies.

So when you have a Wattenberg drilling rig and a Wattenberg completion crew, and minimizing your downtime gives you the same crew and consistency.

So we're not really looking for a production number. We're looking for consistencies in operations that fit within our free cash flow definition. So our growth, as we're done with this, it's going to -- we're using that low single-digit kind of time frame.

Our number range, it's going to be the output based on what's best to stay within our free cash flow, our capital budget range and the production will end up being more of an output as we want to make sure that we have the most efficient operations, which continually to drive value by driving total cost down from a CapEx perspective.

So hopefully, that gives you some insight. And right now from sitting where we are today that $500 million to $600 million CapEx range with low single-digit growth rate, feels very comfortable from where we're sitting in our budgeting process currently.

Your next question comes from the line of Neal Dingmann from Truist Securities.

Svensson on Neal's behalf. So obviously, you all continue to generate really great free cash flow with your current plan. So with that in mind and noting that you don't currently have any activity in the Delaware, I'm just wondering whether you consider directing any activity away from Colorado to the Delaware? And if so, what sort of factors do you look for in order to go ahead and make that decision?

Well, the first and foremost is having returns on our drilling completion activity before we deploy any rate, and we have the challenge of today of doing that at probably a $40 to $45 outlook. We've -- to what Dave Lillo talked about, our capital structure, we're actually excited about where we're at in our overall drilling F&D or returns we can achieve in both basins.

So yes, we are looking at budgets being finalized, but we are looking at kicking off activity in the Delaware again sometime late this year, early next year, both completion and drilling wise. We have, I believe, year-end, around 18 or 19 DUCs in Delaware that obviously will be a first focus and then we'll create new completion opportunities with the drilling rigs.

So we have that in our plans. We're going to balance that with steady state Wattenberg of 1 spudder rig, 1 larger rig for the horizontal portion of the hole and 1 frac fleet. So that, as Dave touched on, will be incredibly efficient. But again, to Scott Meyers comments that he just went through, we have a commitment on capital discipline, pursuing free cash flow, cost control in the company. And all while we believe we can achieve modest production growth.

That's great color. I really appreciate that. So I guess my second question is with regards to your 2021 outlook. So you've suggested overall sequentially flat production into next year with fourth quarter '20 to first quarter '21, declining about 5%. And so given that information, I'm just wondering how we can look at your exit finishing 2021? And if you could comment on that?

Yes. The -- again, just to reiterate, when you look at our '21 production cadence, our low point will be our first quarter and it will be less than 5% is what we see from our fourth quarter.

And remember, there's 2 less days in the first quarter. So that's a big impact of that statement. Then you look throughout with the consistent Wattenberg program and our Delaware program being restarted, you'll see a -- probably the largest jump would be between the first and second quarter or maybe a split between the first and second, second and third quarter, but you're going to see steady increases in all throughout the year. And when you look at the fourth quarter exit rate for 2020 and you compare that to 2021, that's about a 10% change in our forecast. So those are the high levels, steady growth between the quarters, first quarter being the lowest. And first quarter next year being less than 5% of what the fourth quarter is and most of that being driven with 2 last days.

(Operator Instructions)

Your next question comes from the line of Michael Scialla from Stifel.

Congrats on the quarter. This is actually Guillermo stepping in for Mike. I was hoping if you could provide additional color on your 2021 outlook. Given where oil and natural gas prices are today, would it make sense for PDC to focus its 2021 activity plan in areas with higher gas oil ratio?

Well, I would say that when you -- especially when you look at the Wattenberg, we already have a pretty strong plan in place. We have to permit, which takes a year, then you drill the wells. And with our DUC inventory we have, we have to drill -- we're obviously going to draw our DUCs -- or turn in line our DUCs first. So when I look at it, do we have a little bit of flexibility? Maybe. I will tell you that we're drilling or completing wells in all 3 areas next year. And so we're going to have some Plains, some Summit and some Kersey. So we're pretty comfortable that, whichever the way the prices go, we have -- we're having the ability to manage through that. But I don't think you're going to see a major shift just with the permitting process and our inventory in DUCs we already have, we're pretty much set in the cadence that we're going to have.

That's very helpful. And my follow-up is on the hedging program. Do you feel comfortable at your current levels for '21 hedged volumes or would you expect to increase your hedges?

Yes, that's a great question. And I would say, yes, I am comfortable, but that does not mean I wouldn't increase the percentages either. We have a price view. And number one is we always want to consider our first layer hedging, we call our base layer and that protects the balance sheet.

For 2021, I'm pretty comfortable with that. But if we get some prices and we get a little run in the market, we don't mind taking some of that risk off the table. So I would say you could still see some small layers in '21. Our base layers were still looking at layering and base layers in '22. So more of our program right now is focused in '22, but if you get some price spikes or something that we feel that's favorable, we would still consider doing something more in '21.

(Operator Instructions)

I am showing no further questions at this time, I would now like to turn the conference back to Mr. Bart Brookman for closing remarks.

Yes. Thank you, Franzie, and thank you, everyone. Like I said, we're proud of our team here at PDC. We're proud of the quarter. We appreciate your ongoing support through these incredibly challenging industry conditions we're in and look for more positive results in the future. So again, thank you.

And ladies and gentlemen, this concludes today's conference call. Thank you for your participation. You may now disconnect.