PDC Energy, Inc.

Good day, ladies and gentlemen, and welcome to the PDC Energy Fourth Quarter and Year-End 2021 Earnings Conference Call. At this time, all participants are on the listen-only mode. Later, we will conduct a question-and-answer session, and instructions will follow at that time. As a reminder, this conference call is being recorded. I would now like to turn the conference over to your host, Kyle Sork, Investor Relations. You may begin, sir.

Thank you, and good morning. On today's call, we have President and CEO, Bart Brookman, Executive Vice President, Lance Locke, Chief Financial Officer, Scott Myers, and Senior Vice President of Operations, Dave Lillo. This morning, we issued our press release and posted a presentation that accompanies our remarks today. We also filed our Form 10-K. 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-US GAAP financial measures. The appropriate disclosures and reconciliations can be found on slide two and the appendix of that presentation. With that, I'll turn the call over to our CEO, Bart Brookman.

Thank you, Kyle, and welcome, everyone. We have a busy morning with four exciting topics to cover. First, the strategic and highly accretive acquisition in the core Wattenbergs. of Great Western Petroleum. Second, a refined top-tier shareholder return framework for PDC, including the doubling of our base dividend. Third, the terrific results from 2021 and the company's very strong fourth quarter. And last, what I consider an impressive 2022 guide and 2023 outlook. Regarding the Great Western acquisition, let me begin by thanking everyone at PDC who worked on this deal, as well as the Great Western team and their ownership group. Since closing the merger in early 2020, we have been clear about our desire to pursue additional scale with the goal of not just getting bigger, but equally important, getting better. This acquisition is a natural next step towards executing this strategy. It represents a transaction which checks all the boxes. It enhances our free cash flow generation capabilities, brings undrilled locations that complement PDC's existing inventory, enables PDC to increase shareholder returns. It is accretive on almost all PDC key financial metrics, and it honors our balance sheet. I will let the team give the details of the acquisition, but let me touch on some of the highlights. $1.3 billion purchase price funded by cash on hand utilizing our undrawn revolver and private placement of approximately 4 million shares of PDC stock. It includes an estimated 185 million BOE approved reserves and pro forma PDC will be a 1 billion barrel approved reserve company. Production of approximately 55,000 BOE per day. That is at a 42% oil mix. An acquisition price of approximately $24,000 per flowing barrel. Extremely favorable and competitive in today's market. The acquisition brings 315 quality drilling locations. 125 of these are ducts or are fully approved and permitted. The transaction is accretive on several key metrics, including free cash flow, free cash flow per share, shareholder returns, GNA, and LOE. It also improves our greenhouse gas and methane emission intensities as we pursue our 2025 emission reduction goals. Overall, an outstanding deal for PDC, our employees, and our shareholders. Now, let me switch to 2021, a tremendous year. First, congratulations to our operating teams. Three years without a lost time injury in either basin, an outstanding job. During the year, we generated $950 million of free cash flow on a capital spend just under $600 million. We reduced debt nearly $700 million and ended the year with a leverage ratio of 0.6. We returned $245 million to our shareholders, launched a base dividend of 12 cents per share, paid a 50 cent per share special dividend in the fourth quarter, and repurchased just under 4 million shares at approximately $45 a share. We also introduced new and aggressive greenhouse gas and methane emission targets. In 2022, our operational focus and financial momentum will continue to accelerate. Pro forma, we expect to generate approximately $1.3 billion of free cash flow. After we assume the debt from this transaction, we anticipate year-end leverage ratio will be approximately 0.7. Let me provide some highlights around our planned shareholder returns. which Scott Myers will cover in more detail later in the call. I want to start by saying how pleased I am that our board recently approved doubling our quarterly base dividend to 25 cents per share and upping it to 35 cents upon the closing of the acquisition. We also increased our authorized share repurchase program to $1.25 billion for approximately 20% of the current market capitalization. We plan to execute these repurchases by year-end 2023. With regard to our shareholder return framework, 60% of post-dividend annual free cash flow is planned to be returned to shareholders through our buyback program and special dividends if needed. Last and extremely important, the company is not losing sight on ESG, and the team is making great strides here. In 2022, we plan to invest approximately $80 million to further improve ESG performance, including a 10% year-over-year greenhouse gas improvement, 15% methane intensity reduction, and industry-leading outreach programs, including charitable giving, and community relations efforts. We've also made continued progress on our board refreshment, including the addition of three diverse members over the past 12 months. And we have included emissions reductions in our 2022 quantitative metrics and fully defined the governance of ESG at the board level. With that, I'll turn the call over to Scott Myers for more details on the financial outlook of the company.

Thanks, Bart. In many ways, the execution of our financial strategy and success of 2021 positioned us for this accretive acquisition we're announcing today. On the bottom of slide nine, you can see just how much progress we've made cleaning up our balance sheet in the past year. Approximately 75% of our free cash flow in 2021 went toward debt reduction as we successfully lowered our net debt by approximately 40% from $1.6 billion to $900 million. As Bart mentioned, this resulted in a year-end leverage ratio of 0.6. In 2022, much of our focus will be on executing our new shareholder return framework, but we still plan to reduce debt along the way. Assuming a successful closing of the acquisition in the second quarter, we project our trailing 12-month leverage ratio will be at or below a very manageable one times, based on our projections We expect to reduce this to 0.7 by year end, essentially right back where we started. Next, our commitment to consistent and meaningful shareholder returns. Under our new return of capital framework, we are committed to returning 60% of our annual post-based dividend free cash flow to shareholders via systematic share repurchase and a special dividend if needed. As Bart mentioned, we're doubling our base dividend to $0.25 per share. This equates to a yield between 1.5% and 2% at today's prices. Upon closing, we expect to increase the dividend again to $0.35 per share. On an annual basis, this equates to a yield between 2% and 2.5%. As you'll see in a moment, the ability to sustainably grow our base dividend over time is our primary focus when it comes to shareholder returns. Next, in order to execute our 60% post base program, our board increased our share buyback authorization to $1.25 billion. This equates to approximately 20% of our current market cap, and we intend to fully exhaust this authorization by year end 23. On the bottom of the slide, we tried to articulate in the manner in which we will execute our return of capital initiatives in various quantity price worlds. As you can see, In all of the prices, our first commitment is to honor the base dividend. Sitting here today, we're obviously in a bullish price environment, meaning we'll aim to meet our 60% post-dividend commitment predominantly through share buybacks, but the likelihood for a special dividend increases as we look to avoid overly aggressive share repurchases at procyclical highs. We take a long-term look at a return of capital program Since implementing our share repurchase program back in 2019, we've invested $360 million to buy back approximately 10 million shares at an average price of just over $35. Last, with PDC trading where it is today and with a modified pace of our buyback program, we expect to repurchase all the equity associated with this acquisition in the next four to five months. Said differently, we look to retire approximately 1% of our shares outstanding per month. Shifting to the 2022 budget, you can see we provided capital and production ranges as both PDC standalone and pro forma, which is in the blue italized font on the slide throughout the deck. Dave will go into more asset level detail in a couple of slides, but you can see we would expect to invest approximately $700 million in 2022 compared to just $600 million in 2021. The first piece of bridging the gap between the years is us adding a second rig in the DJ in the next month or so. Round numbers, this equates to around $50 million. Next, it's inflation. We began messaging this back in August of last year, and obviously the whole industry is facing a similar set of circumstances. We estimate an additional 50 to 75 million of capital in 2022 to handle the increases to steel, fuel, and labor. From a production standpoint, the plan is expected to generate approximately 200,000 BOE per day and between 62 and 65 barrels of oil per day. From a pro forma standpoint, we plan on adding a third drilling rig and a part-time completion crew for effectively the back half of the year. you'll see in our pro forma full year production ranges of 225 to 240,000 BOE per day and 74 to 81,000 barrels a day. However, this obviously doesn't tell the full story due to the anticipated closing in the second quarter. In the second half of 22, we expect to be producing between 250 and 260 BOE per day and between 82 and 87,000 barrels of oil. While this acquisition is very strong to our 22 projections, it really starts to show its teeth on a full year basis in 23, which can be seen on slide 12. Here we're going to focus solely on the financial benefits of the deal, as Lance will touch on a couple other metrics in a few minutes. Looking at the charts and on the table on the right-hand side of the slide, you'll see the benefit to our 22 and 23 cumulative free cash flow, base dividend outlay, and total shareholder returns. From a free cash flow standpoint, we're assuming $75 oil, $4 gas, 2750 NGLs held flat for each year. As you can see, at pricing well below current script, we are projecting an increase in our two-year cumulative free cash flow of approximately $500 million. while total free cash flow in the performance scenario of $2.7 billion equates to nearly 50% of our current market cap. In terms of the base dividend, PDC standalone is simply $0.25 per share through 2023, while the performance figure reflects our intent to increase the payment to 35% beginning in the second quarter. Neither of these figures bake in the benefit of our share buyback program, which will obviously reduce the total cash outlay. However, neither bake in the hopes to continue to increase the dividend over time. No matter which way you look at it, this acquisition and the projected increase to our free cash flow leads us directly to the ability and the plan to increase our base dividend per share over time. Finally, total shareholder returns are also projected to increase, and in this case, by more than 20% between the standalone and the pro forma cases. This is a clear example, one of the benefits of our new shareholder return framework. As each of these examples, we simply added our base dividend outlay to the projected 60% post-dividend figure. While total shareholder returns of 30% of our current market cap over the next two years is certainly impressive, it's worth mentioning again that these estimates are based on prices currently well below market. All in all, the projections you see here are a byproduct of some of the most efficient operations in highly economic locations in the country. Our team is excited to continue delivering on our free cash flow projections while executing this impressive shareholder return framework. With that, I'll turn the call over to Dave Lillo.

Thanks, Scott. Obviously, much of this call is focused on the acquisition in the next several years. but it's important to highlight the incredible strong finish we made in 2021. Fourth quarter total production of 211,000 BOE per day and oil production of 69,000 barrels per day came in above and at the top end of our expected ranges of 200 to 205,000 and 66 to 69,000 due to the strong PDP and non-op performance a mild winner in the continuous success of our artificial lift program in Delaware. Capital investments for the quarter came in at approximately $135 million, well within our guidance of less than $150 million. We provided basin level detail for the quarter on the bottom of the slide 14 and a bit more color for the full year in our press release. Moving to our Wattenberg program for 2022 on slide 15, you can get more of a sense of our planned activity from both a standalone and planned PERFORMA standpoint. Scott already touched on the service cost environment and our plans to add a second rig in the next month. Here you can see this equates to a planned capital investment of approximately $550 million for the year. Anticipating well costs of $450 per foot reflects a 25% increase compared to a year ago. We all know that crude is almost up 100% at the same time span. However, offsetting much of the inflation we're seeing is a challenge, a real reflection of our world-class efficiencies that our team is currently realizing in the basin. For reference, We recently drilled 10 three-mile laterals from spud to rig release in little over five days average. Those same wells will be completed in more than 20 stages per day. In the past year, we've seen steel costs increase more than 40%. Currently, steel alone accounts for 50% of our drilling costs of a new spud. and 15% of our total AFE. This compares to approximately 33% of our drilling and 10% of our total AFE at the same time last year. As Lance will cover in a moment, these are still some of the most economic projects in the entire lower 48. In addition to the three-mile laterals, our team plans to transition to electric rigs and E-Fleet frac crews while also testing Niobrara A's in certain areas of our field. While much of the attention in the past year has rightfully been on corporate free cash flow generation, the core assets and continued emphasis on operational advancements can't be ignored. Before moving to permits, I want to highlight the pro forma comments on this slide. Looking at the map on the right-hand side of the slide, you can see we've added the range area to our existing areas. Lance will give an overview of this area in a few minutes, but it's incredibly important to note that all 215 locations identified in the range area are either ducts, fully permitted wells, or having an existing surface permit in place. We expect this area to immediately compete for capital and generate returns on par with what you're used to seeing throughout our legacy acreage. In terms of activity and capital investments, we expect to pick up an additional rig and add around 70 completions to our full year program post-close. We expect this to result in a full year pro forma capital investment of approximately $800 million. Shifting gears, slides 16 and 17 provide an update to our CAP and OGDP process. As everyone is aware, we submitted our application for our Gwinella CAP just before year-end. For reference, this document was over 2,000 pages of accumulative impact analysis, alternative location analysis, and a variety of other materials. I want to thank everybody involved in this tremendous process so far. There is still a long way to go with a number of collaborative meetings with a variety of stakeholders, including local municipalities, state agencies, and offset operators. The accomplishment made to date is truly remarkable. We've given a little more commentary on each of the steps in the process in the appendix of this presentation. But as you can see, the benefits of thorough planning are evident. The Gwinelli Cap provides a glimpse at the future responsible energy development in Colorado, if not the rest of the country. As currently designed, this 35,000-acre development plan comprises approximately 450 wells with a minimal footprint of only 25 pads. 100% of the oil, gas, and produced water will be piped, 100% electric power on each location, which will reduce noise and emissions. At PDC, we know this is a key project many of you are keeping your eye on. While it's tough to predict the ultimate approval timeframe, we plan to consistently update the roadmap shown here throughout the year. Moving to slide 17. I'll quickly touch on a few updates regarding OGDPs. First, the Kenosha OGDP. As you can see on the right-hand side, this project recently passed through the completeness determination phase and now has a tentative hearing date with the COGCC in May. At that time, we're hopeful to have permit approval for another 70 wells These wells are not currently slated to be turned in line until 2024 timeframe. Secondly, we've added the Whitney OGDP to the queue. This project represents an additional 16 wells in the future plans. Our intent here is not to show all of the plans and OGDPs moving forward, but to provide assurance that our team is actively converting sticks on a map to approved permits in hand. Next, the BRO OGDP. This is a 30-well project that we acquired from Great Western that also has passed completeness determination phase. Throughout the course of 2022, our hopes is to demonstrate a track record of continuing permit flow under the new rulemaking and take the lid off our risk premium applied to our stock. Finally, I want to call attention to the 215 identified locations in Adams County at the bottom of the slide. As you can see, there are currently 12 DUCs, 105 fully approved permits in this area. There are also 96 locations with a Form 2A. In the past, we've avoided this level of detail regarding our permits, but in this case, we felt it was beneficial to provide. A Form 2A is a surface permit for the future wells, facility, and equipment, meaning it has gone through all the necessary approvals needed for the future development above ground. These locations, similar to all other Colorado locations, are now in need of a Form 2, which is a subsurface permit for each well incorporated in the 2A. Once obtained, these locations will shift into the approved permit bucket, just as all other permits we disclose. Again, look for us to update throughout the year as we continue making progress in this regard. Finally, before turning the call over to Lance for a bit more color on the acquisition, Slide 18 gives an overview of our planned 2022 Delaware activity. While Wattenberg clearly gets the majority of our capital, it is important to recognize the Delaware contribution of more than $150 million of free cash flow in 2021, with 2022 projected free cash flow exceeding the $150 million of total capital investments by approximately $225 million. Similar to 2021, we plan to run a full-time rig and a part-time completion crew, each resulting in 15 to 20 wells being drilled and completed. Similar to Wattenberg, we have some really exciting operational plans in 2022 highlighted in the orange box at the bottom of the slide. First, our U lateral project, which includes six total wells in one section, three of which are U laterals, XRL equivalents in the Wolf Camp A that are exactly as they sound. These wells are shaped like a U as we drill to the end of the leased line and back, and the other three wells are standard reach laterals in the Wolf Camp A and B. These wells were spud in 2021 with completions in January, and flowback is currently underway. Look for more color on this existing project in upcoming months. We also plan to test the second bone springs formation in our central area this year. If successful, each of these projects would be additive to our current year-end inventory in the basin. Importantly, as we digest our Wattenberg acquisition and await well results in the coming months, our team is extremely focused on blocking and tackling in the basin. Our attention is on acreage trades, opportunistic acreage adds, and organic inventory expansion for the time being. With that, I will turn it over to Lance Locke for a bit more color on the acquisition and pro forma PDC.

Well, thanks, Dave. And just as Bart opened the call, it's important to restate our disciplined approach to pursuing value-add scale through acquisitions. As we've continued to share with the market, PDC has a very high threshold for acquisitions, and this slide provides those key criteria. The first starts with high ROC quality, which delivers strong economic value over the long term and across multiple commodity price outlooks. This acquisition is in the core area of the Wattenberg and delivers highly economic locations in the PDC portfolio. I'll touch on this more in a minute. The second and third criteria were already provided by Scott in how this acquisition enhances our absolute free cash flow, free cash flow per share, and correspondingly increases our shareholder returns. Then finally, our acquisitions have to be accretive to all key financial per share metrics, while at the same time maintain our strong balance sheet. So, over the next few slides, you'll see the scale-building financial strength of this core acquisition, including the accretion we expect to realize in 22 and 23. Slide 21 highlights a bit more detail on this $1.3 billion core Wattenberg acquisition. The purchase price consists of $543 million of cash and the private placement of 4 million shares of PDCE common stock, plus the assumption of approximately $500 million in net debt. As Scott shared earlier, we anticipate our cash on hand and our undrawn revolver can comfortably support this transaction, as our leverage ratio is expected to remain added below one time as of closing, with the projection to be added below 0.7 by year end. On the middle of the page, you'll see some of the key acquisition benefits of the Great Western transaction. First, Great Western has an estimated SEC-approved reserves of 185 million barrels equivalent as of year-end 21. Combined with PDC's own year-end SEC reserve engineering reports, our pro forma year-end 21 reserves, SEC, are expected to be 1.0 billion barrels equivalent, which is a significant milestone for the company. Our pro forma pre-tax PV10 value of our SEC pre-approved reserves is nearly $12 billion. based on flat pricing of about $67 per barrel and $360 per MMBTU. Next Great Western produces 55,000 BOEs per day with a product mix of 42% oil and 67% liquids. The 42% oil mix is meaningfully accreted to our base Wattenberg oil mix. Finally, the map on the right shows 54,000 net acres in the blue color. which fits very well with our existing core Wattenberg position. Our new range area located in northern Adams County is also very much in the core of the field delivering very strong and competitive economic returns. Finally, as we provided earlier, the acquisition is accretive to all our key financial metrics and to our greenhouse gas emission intensity. As we transition to slide 22, you'll see a detailed breakout of our existing and acquired inventory by area and permit status. Sticking with the range area, the bottom of the table, slide 22, shows 213 identified locations in this new Adams County area. Of the 213 locations, 117 are either DUCs or fully approved permits, while another 96 locations have approved surface permits in place, known as Form 2As. and they only require the subsurface permit or Form 2s. We appreciate Great Western's long-term planning approach in having already secured approved surface permits in Adams County, such that now we only need to file for approval for the subsurface permits for these 96 locations. Historically, securing a Form 2 permit has been a pretty routine exercise that typically takes approximately 60 to 90 days post-submittal. We look forward to working with the COGCC to move the nearly 100 unpermitted locations to the fully permitted column. For reference, it's worth noting that just last week, 16 of the 46 unpermitted locations we plan to acquire from Great Western in our prairie area received Form 2 approvals and are now fully permitted locations. Additionally, 11 locations in PDC's standalone summit area received their Form 2s this past week. Both of these recent approvals are not reflected in the table and are a clear sign of continual permit flow in the state. While PDC has been focused on the tremendous work Dave and his team are doing with our CAP and OGDPs, expect to also see new approved permits outside of these key projects as we secure our Form 2 approvals. Now let's take a look at the financial strength of our portfolio. This bar graph provides the IRRs based upon two commodity price outlooks, which demonstrate both the tremendous economic strength as well as the resiliency of our Wattenberg inventory. Assuming flat pricing of $75 per barrel, $4 per MCF, and $27.50 for NGLs, as well as our current cost structure, we estimate that nearly all of our 2,100 pro forma locations have an internal rate of return at or above 100%. Additionally, at 50 per barrel oil, 250 gas, and $15 in gels, again assuming our current cost structure of $4.5 million per well, our pro forma inventory generates between 55% and 75% internal rates of return with the new range area projected right at the midpoint of the returns. It's clear from this analysis to see that this acquisition meets our criteria in providing complimentary Tier 1 inventory that immediately competes for capital. With returns like this and low break-evens, we believe our inventory has some of the most premier Tier 1 acreage in the country. Slide 23 contains several graphs that demonstrate the strong value add that Great Western brings to our company. First of all, we gained scale through production growth of about 25 percent on a BOE basis. And importantly, we gained about 35 percent growth on our oil production. This material jump in our overall production drives meaningful reduction to our LOE and GNA metrics on a per BOE basis. The combination of acquiring higher PDP assets in a predominantly cash, low equity transaction makes this deal very creative on a number of fronts. Due to the timing of close, we depicted our improvements on a 2023 basis, but think of this as a second half 22 run rate as well. Importantly, we estimate our pro forma 23 EBITX per share to improve by approximately 25% compared to our standalone levels. Neither of these EBITX per share estimates in the bottom right graph include the benefit of our planned share buyback program, which would further improve the numbers. And then finally, on slide 24, this slide summarizes our true pro forma value proposition for our shareholders. On a relative basis, compared to a comprehensive industry-wide peer group, PDC screens extremely well with an estimated free cash flow yield of 25 percent in 2023. Additionally, our projected 2023 total shareholder return yield, utilizing our new return to capital framework, is projected to be 16% in 2023, which is significantly above the median peer company yield. The last graph shows how PDC screens has maturely undervalued at an EV per 23 EBITDAX multiple just three times versus the median peer group of nearly five times. These metrics, along with where our stock trades relative to our internal after-tax net asset value, supports the aggressive share repurchase program Arden Scott outlined earlier in the call. All in all, we believe this acquisition, coupled with our existing inventory quality and financially driven business model, creates an extremely compelling investment thesis. I want to thank all our teams for their tremendous level of work on this high-quality acquisition. We know there's a lot of data to digest and are happy to turn the call over to the operator for Q&A.

Thank you, sir. As a reminder, to ask a question, you would need to press star 1 on your telephone. To withdraw your question, please press the pound key. Please stand by while we compile the Q&A roster. I show our first question. It comes from the line of Arun Janyaram from J.P. Morgan. Please go ahead.

Good morning, gentlemen. My first question is regarding the outlook on cash return You've outlined $1.7 billion of cash return in 2022 and 2023, including $1.25 billion of buybacks. So is the math here that we should expect the balance of that delta to be in the base and variable dividends? And how should we think about your deck is quite a bit below the strip? If free cash flow is above your reference deck, How should we think about the split between buybacks and dividends?

Yeah, Ron, great question. I would think that when we look at the share buyback, that's a really important part of the strategy, and we're really going to spread that $1.25 billion. The plan is to spread that over the two-year period. So to the point that we don't hit the 60% post-based dividend, you would look for that to be more of a special dividend towards the end of each of the reflective different years. When you look at the bull cases, that's what we tried to outline on our deck on page 10, I believe, is that when we're in mid-cycles, we think we can do it through a total share buyback. But when we get into the bull environment, we're going to lean towards more special dividend towards the end of the year. We just don't want to keep buying back shares. We want it to be systematic. We buy a little bit less when the price goes up, but a systematic process throughout the year is kind of the game plan for us. And then also in 2023, you know, we set this up so we can continue to grow in the base. We don't know what that number will be yet, but we fully expect to be able to do that in 2023 as well.

Great. And just one follow-up. On the 2023 preliminary program, you guys have outlined similar capital to 2022 in and 0% to 5% total in oil production growth. But can you give us the baseline from that, Scott? Is that similar to the $900 to $1 billion? And is the growth rate based on the second half, 22, pro forma, or the full year?

Yeah, I would say it's more, when you say similar, similar to what we're going to be doing in the second half of the year. So if you look at an all-in capital range for 23, I mean, clearly we're going to have an extra four months of activity. Now, that doesn't mean it's four full months, but we plan on running three rigs in the DJ full year. So that adds a little bit of capital in 23. Plus, you know, Dave alluded to 70 completions. You could see that going up to 100 completions. So I'd say capital between 22 and 23, 50, 75 million-ish, add somewhere in that neighborhood. Very similar capital spend or burn rate to what the second half of the year is. As far as production, I would say if you look at that second half run rate of 250 to 260, look for us to have that 0% to 5% growth off that base number at 23.

Great. Thanks a lot, gentlemen. Appreciate it.

Thank you.

Thank you. I show our next question comes from the line of Neil Dingman from Truist. Please go ahead.

Morning, all, and congrats on the deal. Really the first question I just had, was for Scott, maybe on that, that payout, you know, you guys obviously now have a great, you talked about the 60% minimum sort of post free cashflow. And I'm just wondering what would cause you all to push that to a high level? You know, we've seen some, you know, to me what I think is a little bit crazy levels of over a hundred percent payout of free cashflow and, You know, others remain down closer to 40%, 50%. So I'm just wondering, you certainly have the, you know, strong balance sheet. You're going to have, obviously, great free cash flow. So I'm just wondering more internally, you know, when you and Bart think about that, what's going to drive the sort of degree of that payout?

Yeah. No, no problem. And we tried to do a little bit of that on slide 10 in our different environments, but I would say that, Number one, with this transaction, we are adding a bit of debt to the books, and we'd like to continue to be able to pay that down. Our goal is by the end of 2023 to get that back down to about $1 billion. Well, when we get that back down to $1 billion in 2023, again, we don't see ourselves being a debt-free company. We think having a little bit of permanent debt out there is always a good thing. So when you're going through this, paying down some debt, I think, is the first avenue of that extra 40%. In lower-price environments, we feel our structure is very sound, that we'd probably even be more aggressive than on that 60%, and that's what we call in our bearish kind of environment. But I would say look to stay around that 60% to 65% probably for at least this year as we're still working that new debt down that we just got. And once we get that down to $1 billion, you could see that going up more. But again, we don't want to measure ourselves on a quarter-by-quarter basis We're going to measure ourselves through a whole year. So you could have one quarter that's a little bit higher and one quarter that's a little bit less. But by the end of the year, we'll true up to that 60% number at least, if that makes sense.

No, very crystal clear. Thanks, Scott. And then second, maybe, Bart, for one of you guys, just, you know, my question is on really well economics specifically. I like that slide. Twenty-two, you rank your Wattenberg areas by hours. My question is if you would add, you know, the Great Western locations and – you know, add your Delaware. I'm just wondering how these would sort of stack up against your others on that slide.

Yeah, Neil, I think the Great Western locations are highlighted in the middle of that bar chart, right? Oh, there it is. I'm sorry. Delaware would be in that 50% probably to 70% range on IRRs. I don't have the exact number, Dave, but they'd be right in the hunt. That's pretty close, yeah.

Very good.

Thank you. Thank you. I show the next question. It comes from the line of Michael Schaller from Stiefel. Please go ahead.

Hi. Good morning, guys. Congrats on getting the deal done. I wanted to ask you about that, how the deal came about. Correct me if I'm wrong. I think Great Western was looking for an exit for a while. How competitive was the process? Anything you can say to that?

Yeah, Mike, this is Lance. You know, we probably can't go into a lot of the details around the competitive process and the nature that they provided there other than just to say, look, I can assure you our teams had a real long look at this opportunity. We really cut it apart in multiple ways and just did a very good job of ensuring that we had the right evaluation, the right risk analysis in arriving at this evaluation. So, again, Well done by the teams, and also from a midstream marketing standpoint, there was four midstream providers here, so it also brought some basin diversification from a midstream standpoint.

Yeah, Mike, I would just add, I view it as very constructive on all parties, the team at Great Western, their ownership group, and obviously the PDC team, but to Lance's point, this is a good negotiation and fair, and we're happy with the end product here.

Yep. Okay. And I wanted to ask on the permitting process, Lance, you said getting the subsurface is typically kind of a 60- to 90-day process. Once that's done, what's the process from there, and what's the timing of getting those other 96 locations in Adams County permitted?

Yeah, I'll start, and then I can turn it over to David for some additional comments on it as well. But I think the really neat thing in Adams County is that Great Western has secured all the surface permits for these 95 remaining locations that we have valued in this acquisition. And that's what takes the lion's share of the time is getting the 2As approved, and they've done that in the past. So now for us, it's a filing with the state, the COGCC, to get approval for a subsurface permit. And those have been running probably in the 60-day type timeframe, plus or minus, over the last few months. But we'd say, and said in our prepared comments, it's more like 60 to 90 days. So once those are approved, we have our permits, and we're permitted to drill. So it's fully approved at that point in time.

Yeah, so when you think about a 2A permit, We go back to the 2A, which is the surface permit. There's a number of wells that are established in that permit. And then the 2As are just the wellbore construction. So we go back and file and make sure that the Oil and Gas Commission, we work with them to make sure that we have the cements in the right place, the casing in the right place, that we're protecting all the freshwater sands and those type of things, but a subsurface permit at that point. which really hasn't been a big problem in the last previous years, even under the new rules.

I guess if I could follow up then, sorry to take another question, but if you get those in that next 60, 90-day timeframe, would those move up in the queue, or where do you think those would land in terms of the drilling process?

Yeah, you know, based upon where we sit today, I mean, we're waiting on a few permits that have been filed to build into the 22 program for the Great Western Assets, but they've been at the state now for a little over a couple of months, so there's a few more that are coming from that. So I think as you look at the 22 program, Mike, we're in a pretty good spot there with permits that are already approved and ready to go, and there's a few more that are coming in the door. It shouldn't be too much longer to have that as well, so I think we've got this 22 program pretty well buttoned down, if you will, and Great Western's done a good job really managing that process for us.

Yeah, I agree, Lance. On the legacy side, you know, we have 145 ducts and 230 approved permits, which we're working off our legacy side with our two drilling rigs we'll be running through the rest of the year. And then on the Great Western side, they have their program kind of lined out and with permits in hand. So I think we're in good shape, real confident.

Very good. Thank you, guys. Thanks a lot.

Thank you. Aisha, our next question comes from the line of Steve Deckett from KeyBank. Please go ahead.

Hey, guys, just wanted a little more color on stepping outside of Weld County for the first time with this deal. Thanks.

Yeah, so this is Lance. You know, from our perspective, we took a real deep dive looking at Adams County, and it's actually northern Adams County. And just a real shout out to our regulatory and operating teams that really did a deep dive on each one of the pads here. And we really got comfortable with the opportunity of coming into Adams County. and to continue in the great work that Great Western Team has done there by continuing with the permitting process and getting those permits in place to drill. And so I think from our perspective, we talked about earlier with our prior comments around having a long time to look at this opportunity. That was one of the key areas that we looked at. And so at the end of the day, acquisition valuation here you know, consisted of just paying for the ducts, the approved permits, and then the surface permits that just then have to file the subsurface permits with that, with a very well-established long-term process for those approvals. So we feel that all came together very well in arriving at the valuation.

Steve, this is Bart. Yeah, just to add to Lance, it probably was the most – researched aspect of this project for us of taking the time to really understand the regulatory environment in Adams County and as he said we felt really good about the project in the value we put on the ducks and the approved permits is what we paid for obviously including the PDP but also we're going to build on what Great Western did as far as their tremendous community relations and we will we will apply the PDC formula to this in community relations, charitable giving, and being very involved in the county, and also obviously responsible operations in the end.

Got it. Okay, great. And then just on the Wattenbergs, it looks like there's a little bit less activity year-over-year on a standalone basis. Is that correct versus 2022? Or sorry, 2021?

I think it's – I'd call it similar. I mean, some of it, it's the lateral length. When you look at number of wells, I think we had somewhere close to 60 to 65 one-mile locations completed in the third – most of those were in the third and a little bit in the fourth quarter. So that makes the well count a little bit or turn in line count a little less. But when you look at total footage, total miles completed, it's plus or minus 5%.

Got it. Okay, great. Thanks. That's all for me.

Thank you. As a reminder, to ask a question, you need to press star 1 on your telephone. To withdraw your question, please press the pound key. I'll show our next question. It comes from the line of Oliver Huang from Tudor Pickering and Holt. Please go ahead.

Good morning, all, and thanks for taking my questions. One real quick, in the range area, could you provide some color on the level of spacing that Great Western has been operating on the asset base and any changes that you all might look to implement on the assets, whether it's on the completion design, spacing, or lateral length, or pad sizing?

Hey, this is Lance. I'll start and then I'll kick it over to David there. In our acquisition evaluation, we used the spacing that's within the range of what PDC uses in our Wattenberg field. It's approximately 20 wells per section is what we utilized here on this opportunity. That was based upon a lot of work that our BD teams have done to assess the resource recovery, the type curves, et cetera, a lot of work that was poured into that. to really drive home those numbers. Again, the type curves are based on that type of spacing. There may be an opportunity, depending on what the 2A says, as far as how many wells that you can have permitted to ultimately drill, that we may find opportunities in a few of the pads through the areas to increase that spacing. That's something that will continue to work, and now that we get more teams involved, we'll be able to do that.

Just to clarify, that opportunity increases based on the permit that was originally submitted by Great Western.

Right. So that's in every 2A, and that's a good point that Bart made. In every 2A, it says exactly how many wells that you get to drill under that surface permit. And so to the extent that the number in the 2A that was approved, it was greater than 20 wells per section total, that provides PDC an opportunity to consider additional down space and be on the 20.

Great. That's helpful color. And for my second question, just given the greater focus in the DGA following this morning's announced deal and the minimal scale in the Delaware, wondering if you might be able to provide some color in terms of how you all see the Delaware fitting into the business on a longer-term perspective.

Yeah, good. No, that's a great question. I'll share some thoughts on that and then turn it over to Bart as well on this. But, you know, we like the Delaware position. We're generating good value, as Bart talked about, the rates of return that we expect to generate from our programs there this year. You know, clearly it's got a much, much smaller, you know, inventory life. But at the same time, with the tests that Dave talked about, the second bone springs, the U-laterals, We may have a couple WolfCamp C tests next year to test. So there's things we think we can do to continue to sustain that over time. And I mean, the asset is bringing some really good free cash flow at the asset level. And so it's one that fits our portfolio well, and it's economic in our portfolio. So I mean, as Dave, you know, ended his comments on, we'll continue to look for opportunities that, you know, that are bolt-on, that make sense for the company to find ways to add some incremental values there. Right now, again, our focus is on getting this wonderful opportunity, Great Western, integrated into the company and to deliver on all the numbers that we're talking about here today.

Yeah, Oliver, just to add to what Lance is saying, right now we've got approximately four years of inventory, and we're proud of the team. We've got a terrific plan really mapped out for the next couple of years. I think everybody's going to be really excited by some of the early results we're seeing right now in the basin. So overall, you can expect us to really focus on blocking and tackling on the acreage and inventory as Dave and the team recently added a 1280 on some inventory that we're really excited about. And then Dave's got, as he noted, several organic opportunities that we're going to focus on. So we've got a lot of confidence. And as Dave said, this is, you know, I think about 20% of the free cash flow generation for the company.

Great. Thanks for the time.

Thank you. Aisha, our next question comes from the line of Michael Shiala from Spiegel. Please go ahead.

Hey, Mike.

Yeah, I just wanted to ask on some other private topics. still in the uh basin i know everybody says they have a high bar on on m&a you guys obviously do um do you think there are other opportunities that would make any sense to look at i mean great western seemed to fit perfectly with your existing asset base and i think it's the largest of those privates but um does anything else make any sense to even consider in the dj

You said that really clear because when you look at Great Western at 55,000 barrels of oil equivalent per day, the remaining private companies, this was the largest of the remaining companies, and they have an acreage position that's in the core area of the field. This one just really came to the top for both of those key reasons for our company. There are other private operators in the basin there. I mean, we continue to, just as our normal course, look at potential opportunities over time. But this one really stood out to us to being the best opportunity. And this is why we pushed forward with the Great Western team on this one. But we'll continue to look at opportunities in the future. But at the same time, just the focus is on getting this integrated, getting all our processes in place, getting all our people in place, and executing cleanly on this one. And so look for us to really focus on this opportunity and deliver results from this one. That's our priority and our focus.

And Mike, let me just add to this a little bit, just to clarify. We're really excited on some of the technical things that Dave talked about. We obviously have an aggressive program mapped and planned out. We've got a full court press on the permit side, and now we have the integration of this deal. So I think we want the market to look at 2022 as an execution backslash integration focus for PDC.

Yeah, it makes a lot of sense. Just wanted to ask Dave one more on the permitting process for the Kenosha OGDP. You've got a hearing coming up in Weld County and then the COGCC after that. But what do you expect from that Weld County hearing? And then what's, you know, how much, I guess, potential for the timing to move from there? I know you're targeting kind of that May timeframe for a COGCC hearing in I guess I want to see what kind of variability you anticipate with that process.

Yeah, Michael. Right now we're pretty confident in the Kenosha OGDP. It's going to add about 70 locations to us. We have 90% of the informed consent for that. So it'll be a traditional hearing. We've been talking to the Oil and Gas Commission. We've had good feedback back and forth on... everything that we do up to this point. And I feel real confident that I think our commission hearing date is May 8th, and hopefully we're going to walk away out of that with 70 more permits in hand.

Sounds good. Thank you.

Thank you. Our next question comes from the line of Nicholas Pope from Seaport Research. Please go ahead.

Good morning, guys. Morning, Nicholas. I kind of wanted to follow up a little bit on the Permian versus the DJ kind of returns and kind of where the focus is. I mean, when I look at the chart on the returns you guys are generating and the amount of inventory you have in the DJ, it's a little bit tough to see how acquiring – inventory in the Delaware could possibly compete with, I guess, what would be adding activity or adding more rigs in the DJ and just kind of attacking the organic opportunity you have. And so I guess, really, I'm kind of asking, what is the trigger to put more activity back into the DJ? I mean, beyond this acquisition. I mean, I guess... I mean, if you look at the incremental dollar, it seems better spent in the organic versus acquiring in the Delaware. So what would that trigger be?

You know, I think from our standpoint, we take a long look at the value of a portfolio and having assets in two basins. We really like that positioning, and we think that's something that can be value-enhancing to the company. because there's always just different, you know, risks that you can see in different states over time and whether it's midstream, you know, constraints or whatever other, you know, opportunities that arise. So I think at the end of the day, the Delaware is a good foothold for our company. It's got a solid base of production and it's got the additional inventory, things that we're looking at that David highlighted that we're testing this year. So, you know, just, you know, The way I like to think about this is that, again, our focus is on integrating Great Western this year. Are there opportunities where we can come out and say, for example, farm in and drill on someone else's land in the Delaware? I mean, we're going to probably look at that opportunity because those could deliver very solid results for the company. But at the same time, we're going to always manage our capital spend and our free cash flow model and make sure that we have that right balance corporately as well. There are several things and factors that go into that, but again, having a portfolio and knowing this asset still delivers very strong value to the company makes it something that we think is still a key part of our portfolio.

Nick, just a couple of adds to this. We also have in Wattenberg, obviously, a new regulatory environment. With 181, the permit flow, we have confidence in obtaining permits, but accelerating capital spend in the Wattenberg right now, obviously we get some of that through the acquisition, but our inventory life is probably 10 to 12 years. In Wattenberg, the acquisition will be drilled at a comparable pace, so we really didn't extend the runway for our inventory there. So having the balanced operations, the balanced capital, delivering strong value for our shareholders in both basins, and then obviously there's the balance of the regulatory risk that we're always looking at too. So there's a variety of reasons for us to stay the course.

Got it. That's helpful. I appreciate the time.

Thank you. Our last question comes from the line of Arun Jayaram from JP Morgan. Please go ahead.

Yeah, just a quick follow-up. It doesn't look like the deal really highlights any real synergy, so it's not really being underrated by, call it aggressive assumptions on synergies. But, Scott, I was wondering maybe if you or Lance maybe could talk about some potential benefits on the synergy front from the transaction.

Yeah, clearly with a private operator, there's not the numbers that are sitting out there, but I will tell you that there is some G&A reductions, but it's more on what we have to add to run the operation compared to the additional production we're getting. So I do think you'll see, like on Lance's slide, G&A per BOE does go down. you see a little bit of drop in LOE as well. That's more of just a mixed issue where their operating practices on a barrel of LOE was pretty consistent with ours and pretty strong. I do think there's some opportunities there with having three rigs running, having some additional cost savings there, one field office over time, a little bit less overhead, but we thought the merits of the deal kind of where it was, stacked up on itself, and I'm sure Dave and his team will do the job that they always do, and we'll find little bits, little nuggets here and there as we go through this year, 22, and then 23. So I'm sure there will be a little bit, but I think the rest of the metric is pretty much still in ourselves.

You know, in the room, just from a drilling standpoint, again, we touched on earlier that there's probably some areas where we may find more than 20 wells per section density on the already-affirmed Form 2As. And one of the things we haven't touched on is that There's additional locations even beyond what we've discussed in Adams County that we haven't valued as well. Those would be the going more the OGDP and CAP process there too. So there's things that we think we'll find over time. I mean, clearly David and his team have done a tremendous amount of work just in efficiency on drilling pace and timing and things along those lines and stuff. So there's a lot of stuff that I think will manifest itself over time. We just didn't underwrite to it in the acquisition purchase price.

Great. Thanks a lot. Thank you. I'm sure there are no further questions in the queue. At this time, I'd like to turn the call back to Mr. Bart Brookman, CEO, for closing remarks.

Yeah, thank you, Dylan. Thank you for hosting the call. And a great day, transformational in our free cash flow framework, shareholder return framework, and obviously financial Very excited about the Great Western acquisition. So more to come as we integrate, and we thank everybody for joining the call.

Thank you. This concludes today's conference call. Thank you for participating.