Good day, and thank you for standing by. Welcome to the PDC Energy fourth quarter 2022 c onference call. At this time, all participants are in a listen-only mode. After the speaker's presentation, there will be a question and answer session. To ask a question during the session, you will need to press star one one on your telephone. You will then hear an automated message advising that your hand is raised. To withdraw your question, please press star one one again. Please be advised that today's conference is being recorded. I would now like to hand the conference over to your speaker today, Aaron Vandeford, Director of Investor Relations. Please go ahead. Thank you and good morning, everyone. On today's call, we allow 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-K. The press release and presentation are available on the investor relations page of our website at 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, including a discussion of factors that could cause actual results to differ materially from forward-looking statements can be found on slide two in the appendix of that presentation. With that, I'll turn the call over to our CEO, Bart Brookman. Thanks, Aaron. Good morning, everyone. Let me open by saying, over PDC's entire 50-year history, 2022 stands as the most successful year by almost every measure. A record free cash flow level of $1.4 billion, $1 billion of which was returned to our shareholders in the form of share repurchases, our fixed dividends, and a $0.65 per share special dividend this past December. Production for the company, a record 85 million BOE. In May, we closed the highly accretive Great Western acquisition, solidifying our already exceptional core Wattenberg position in driving solid production and reserve growth. Reserves year-end 2022, a 440% reserve replacement for the company as we grew reserves to 1.1 billion barrels of oil equivalent. In drill permits, I wanna extend the most sincere thank you to our regulatory group, permit specialists, land team, operations, and their compliance groups. In 2022, we cracked the code on obtaining permits in the state of Colorado. Through our approved OGDPs, CAP, and Great Western acquisition, we now have permits and DUCs in hand for our development program through 2028. Emissions for the company. Last year, we materially beat our 2022 emission reduction goals with over a 30% reduction in greenhouse gas emissions and over 50% reduction in methane intensity. Outstanding results. Based on this achievement, expect us to roll out even more aggressive emission goals in the near future. The recently approved CAP demonstrates the company's focus on long-term development aligned with our ESG goals, these emission reduction goals, and quality development plans. A reminder, within this CAP, we have 33,000 net acres, 450 wells, 22 surface locations in a permit life of 10 years. Technically, we are implementing significant best business practices, including deploying more 2 mi- 3 mi laterals, pursuing 100% electrification and state-of-the-art facility designs. Within the CAP, the company will reduce greenhouse gas emissions by 72% from our 2020 design, resulting in some of the lowest emission production in the world. The most compelling aspect of the CAP is, while achieving these extremely low emission levels, the drilling projects will be some of the most resilient and economic projects in the country. Lance will provide more color on this in a moment. Building on these 2022 successes, I'd now like to turn our attention to the company's plans for this year. We anticipate 2023 will be another success story. Production of 95 million BOE or 260,000 BOE per day. Projects in both basins are well mapped and highly economic. Free cash flow is anticipated to be $825 million. That's at $75 oil and $3 natural gas on a capital spend of approximately $1.4 billion. We will modestly reduce debt levels for the company and anticipate year-end leverage ratio of 0.5. Our commitment to returning 60% of the free cash flow, post-fixed dividend remains strong. In our recent announcement on increasing our fixed dividend to $0.40 per share and expanding our buyback authorization by $750 million both demonstrate the company's commitment to shareholder returns. Last for my comments today. Sincere congratulations to our EHS and operating teams in both basins. Texas and Colorado operations are approximately five years with no lost time injuries, a record for the company and a signature of PDC's commitment to safety. A job well done. I'll turn the call over to Lance Lauck for an update on the company's reserves and inventory. Thanks, Bart. Slide seven highlights our 2022 year-end proved reserves, which increased to approximately 1.1 billion barrels of oil equivalent. This increase represents 35% compared to our year-end 2021 proved reserves and was driven by our Great Western acquisition and by our annual reserve additions and revisions. This is a very sizable reserve base and one that can deliver material and sustainable value creation in the future. Overall, we generated an exceptional proved reserve replacement of 440% in 2022. Equally important, we generated approximately 220% proved reserve replacement through the drill bit, which demonstrates the high quality of our Tier One asset base. At the SEC flat price deck of approximately $93 per barrel at $6 gas, our 2022 year-end proved reserves generated a pre-tax PV-10 value of approximately $19 billion. I would also like to highlight that we have a very resilient reserve base. Assuming a flat $50 oil case, PDC reserve volumes only declined by approximately 2% from the SEC price case. This again is another measure of the highly economic nature of our Tier One asset base. Moving now to slide eight, I wanna take a moment and provide some additional detail on our best-in-class Tier One Wattenberg inventory. With the integration of the SRC assets and now Great Western assets, we have meaningfully consolidated our position in the core of the play. We have historically provided inventory details by geographic area, in order to more clearly describe our Tier One economics, we're providing our drill well economics by their subsurface characteristics. This requires a breakout of our inventory by the respective reservoir phase windows. At year-end, we have identified more than 2,100 core economic locations, inclusive of 200 DUCs in the Wattenberg Field. As shown on the slide, our locations encompass four distinct reservoir phase windows, including two black oil windows, a light oil window, and a retrograde gas window. This slide highlights that four of our five geographic areas have more than one reservoir phase window. For example, the Prairie area to the north has a black oil window as well as a light oil window. While our Summit, Plains, and Kersey areas have three distinct phase windows. Our Guanella CAP acreage is primarily located in the light oil and retrograde gas windows. On the next slide, I'll highlight some of the differences in EURs and economics in each of the phase windows across our core Wattenberg position. Continuing on to slide nine, we provide a detailed breakout of our approximately 2,100 locations by phase window. Before touching on the economics, I want to point out how de-risked our inventory is from a permitting perspective. Overall, our year-end inventory of more than 2,100 locations are over 50% permitted, including the CAP, which gives us tremendous line of sight into multiple future years of highly economic development. Our highest permitted phase window is in the Black Oil Range acreage area that we acquired from Great Western. While it's 100% permitted, we wanna note that our teams are working on various inventory expanding opportunities that was not included in the original transaction. Our lease permitted acreage is in the black oil window in the north. It's also located in very rural areas with less permitting risk due to minimal building units and structures to plan our surface locations around. We look forward to pursuing these permits in the future. The table on this slide highlights our per well reserves for our 2 mi laterals, which range from approximately 460,000 barrels with 48% oil in the northern black oil window to 900,000 barrels equivalent with 20% oil in the retrograde gas window. The EURs and oil mix percentages vary between each of these phase windows. The key takeaway is that all four phase windows deliver exceptional economics that range from 63%-96% internal rates of return based on $75 oil and $3 gas. As we start development of our Guanella CAP assets in 2024, keep in mind that the CAP is located in the light oil and retrograde gas windows. These phase windows will have a higher liquid-rich gas component, but they also deliver some of our largest EURs and economics in the company's inventory. These two windows generate an average rate of return on 2 mi lateral wells of nearly 100% and 85% respectively, again, based on $75 oil and $3 gas. While the Black Oil North window represents a lower EUR of 460,000 barrels equivalent, it also has the highest oil cut at 48%, which still generates approximately 63% rate of returns at the same price deck. One final comment, all phase windows deliver strong oil volumes. Dave will cover more of this in his comments next, but I wanna highlight that our oil volumes provide a strong base for economics, allowing for the gas and NGL contribution to enhance the returns. Before handing the call over to Dave, I wanna summarize this section of our earnings call by sharing that PDC today is in the strongest position in its 50-year history. We have tremendous assets, a great team, a strong financial position, and confidence in the regulatory environment. I will now pass the call over to Dave to cover some of the operational highlights for the quarter. Thanks, Lance. Jumping in on slide 11, I wanna review some of the operational highlights for the quarter. Total production for the quarter came in at 22.7 million BOE, or approximately 247,000 BOE per day. Oil production for the quarter was 7.4 million barrels, or approximately 80,000 barrels per day. Our production for the quarter was strong, especially when accounting for approximately 450 MBOE of production that was impacted from the December weather event that hit many in the industry. Our team did an amazing job of proactively managing the extreme cold weather in Colorado and Texas, minimizing production impacts, and most importantly, keeping our employees and contractors safe. On the expense side of the equation, we invested approximately $345 million during the quarter, slightly above our implied fourth quarter guidance. The slightly higher capital for the quarter was tied to increased non-op activity, field-level efficiencies both on the drilling and completion side as our teams continued to set records, investments related to the CAP and continued inflationary pressures. As we look into the 2023 plan and our budgeting, we are confident that we have captured each of those incremental investments appropriately. Scott will discuss the 2023 capital plans in more detail shortly. During the fourth quarter, our team maintained great focus on managing costs and our LOE for the quarter was $3.04 per BOE. An all-in G&A expense totaled $1.60 per BOE. In the Wattenberg Field, we invested approximately $320 million to run three drilling rigs and two completion crews during the quarter. We spudded 53 wells and turned in line 50 wells. For the quarter, production in the Wattenberg averaged 219,000 BOE per day, of approximately 32% was oil. LOE for the basin came in at $2.52 per BOE, highlighting the low-cost nature of our operations. In the Delaware, we invested approximately $30 million to maintain our one full-time drilling rig activity level focused on batch drilling operations, and we ran an average of one and a half workover rigs to manage our base operations in the field. Production in the Delaware basin averaged 28,000 BOE per day, of which approximately 39% was oil. LOE in the basin came in at $7.03 per BOE and is reflective of the continued workover activity during the quarter. Moving to slide 12, I wanna take a little more time to dive into the Wattenberg Field operations and build upon some of the details Lance provided earlier in the call. In Wattenberg, our Wattenberg assets has industry-leading economics and years of tier one inventory development mapped out. Before highlighting the longer-term outlook in the basin, I wanna provide an update on our 36 well Gus and 28 well Cordon pads that are beginning to be turned on in line in our new acquired Range area. Completions activities on these two larger pads begun in the fourth quarter, and we're happy to report that the wells are coming online, meeting our pre-completion estimates. As we discussed on calls before, larger number of well paths where acreage supports can reduce surface footprint and the impact to communities while driving efficiencies. Production from these 60+ wells that are in process of coming in line now will support our planned production growth into the second quarter. Turning focus to our longer term view in the basin, our operations are supported by the consistency that the development in only a core Tier 1 asset can provide. Though we have historically and will continue to turn wells in line across multiple phase windows, our oil curve remains very durable, yielding more than 22 barrels per lateral foot consistently over a representative five- year development plan. It is important to note on the upper left-hand graph of the slide, our incremental recovery per lateral foot in 2025 and 2026 are tied to bringing online larger EUR wells in our CAP acreage. This incremental production on top of a consistent oil component further supports our strong economics. Finally, I wanna highlight the depth of our economic inventory. When considering the more than 2,000 locations Lance highlighted, approximately 80% of these locations break even below $40 per barrel price without adjusting current well prices that would likely decrease in such a commodity environment. If there was one chart that shows the differentiation of our asset amongst peers, this is it. The deep inventory of projects that is incredibly resistant to changes in commodity prices support our long-term sustainable cash flow model. Finally, on slide 13, I wanna provide a brief update on the Delaware asset. During the quarter, we ran one to two workover rigs as part of our normal operation to support our base production. Additionally, we continued our batch drilling operations utilizing one full-time drilling rig. The batch drilling process is where we drill the surface of each of the wells on the pad before moving on to the intermediate sections and finally drilling each of the lateral sections. We anticipate this process may result in reducing drilling days and ultimately costs. The completion activity in the field resumed as planned in January of this year. 2023 program is preliminary focused on continuing develop of the Wolfcamp A and B zones. We will also evaluate opportunities in the Wolfcamp C and Third Bone Spring intervals, where offset operators have had success. Success in these zones would be inventory accretive for our asset base and extend the life of years of our operation. At the end of the year, we have identified approximately 30 core economic locations, inclusive of 12 DUCs in our inventory. At current development pace, this represents more than three years of operations. We have also identified approximately 40 contingent additional locations targeting other known zones and locations with shorter laterals that will require improved pricing or additional evaluation before including them in our core inventory count. With that, I will turn the call over to Scott Meyers. Thank you, Dave. Starting on slide 15, as has already been pointed out on the call, 2022 was an exceptional year operationally for PDC, that has translated to approximately $1.4 billion in free cash flow, a record for the company. We received a pre-hedge realized price of approximately $50 per BOE, while operating expenses came in at approximately $8 per BOE. Our G&A came in as expected at approximately $1.60 per BOE, exclusive of the approximate $0.22 per BOE of cost associated with the Great Western acquisition. For the fourth quarter, we generated approximately $260 million of free cash flow. This is quite strong considering the decline in pricing in the fourth quarter and the planned increase in investment tied to adding the second DJ completion crew during the quarter. Moving to slide 16, I'd like to highlight a few details on our shareholder returns program. In the fourth quarter alone, we returned approximately $350 million through our share buyback, $0.35 base dividend, and $0.65 special dividend. Ultimately, for the year, we returned $1 billion by buying back approximately 12% of our outstanding shares and exceeding our 60% post-base dividend target. Our returns framework that we laid out earlier in 2022 is underpinned by the robust inventory of economic long-lived locations. It has allowed us the flexibility to execute on the Great Western acquisition, increase our base dividend while meaningfully reducing debt. On slide 17, I wanna quickly highlight the continued strength of our balance sheet. During 2022, we reduced our debt by approximately $530 million from the peak level after closing the Great Western transaction. We exited the year with approximately $1.3 billion in long-term debt and a leverage ratio of 0.5x. Our only near-term commitment is $200 million due in 2024, which can be easily paid by our forecasted free cash flow. On slide 18, I wanna continue the shareholder return topic and outline some of our 2023 return guidance. Using the midpoint of our anticipated 2023 capital investment guidance and the ability to generate more than $2 billion in adjusted cash flow from operations in a $75 per barrel and $3 gas world, we target being able to return more than $550 million to our shareholders in 2023. We remain committed to returning 60%+ of our annual post-dividend free cash flow to shareholders via systematic share repurchases and a special dividend if needed. We continue to use share repurchases as the primary tool in our shareholders return program and anticipate being able to buy back another 7%-10% of our shares in 2023. We are establishing a track record of increasing our base dividend, as we announced last week another increase to our quarterly dividend from $0.35- $0.40 per share. This marks the third increase and second consecutive annual increase since implementing the dividend in 2021. Through Tuesday, we have invested approximately $83 million to repurchase 1.3 million shares this year. Combined with the increased dividend of $0.40 per share announced last week, we've already committed $118 million of returns during the first quarter. Finally, on slide 19, I wanna provide more detailed guidance for 2023 and the first half of the year. We anticipate 2023's capital investments of $1.35 billion-$1.5 billion, which generates between 255,000-265,000 BOE per day and 82,000-86,000 barrels per day of oil. In the Wattenberg Field, the company expects to invest approximately 80% of the total capital in 2023. By running a three-rig program and one full-time plus a part-time completion crew, we plan to spud and complete approximately 200-225 wells. The capital budget also includes non-op, infrastructure for our recently approved CAP, land, and ESG-related projects. In the Delaware, the company plans to invest approximately 20% of the total capital investments by running a one-rig program and a part-time completion crew. We plan to spud and complete approximately 15-25 wells in 2023. In the first quarter, the company expects to invest between $400 million and $475 million, with total production being in the range of 240,000-255,000 BOE per day and 78,000-84,000 barrels per day of oil production. In the second quarter, the company plans to invest between $325 million and $400 million, and total production to be in the range of 257,000-272,000 BOE per day and 84,000-90,000 barrels per day of oil production. This is a material step up in production as we begin to receive the full benefit of the activity level in the first quarter that includes more than 60 Wattenberg TILs and 12 Delaware TILs, of which almost all occur in the second half of the first quarter. To summarize our call before we move to Q&A, our strong execution in 2022 helped us expand the foundation for PDC's continued and long-term success in building value for our shareholders. We exited the year with approximately $1.1 billion equivalent Tier one proved reserves, a rock-solid balance sheet, and a durable inventory of projects capable of driving a sustainable free cash flow for the years to come. I'll now turn over the call to the operator for Q&A. Certainly. As a reminder, to ask a question, please press star one one on your telephone and wait for your name to be announced. To withdraw your question, please press star one one again. One moment while we compile the Q&A roster. Our first question will come from Gabe Daoud of Cowen. Your line is open. Thank you. Hey, everybody. Thanks for all the prepared remarks, and for taking my question. Maybe just starting on the 2023 guide, Bart, could you maybe just give us a little bit more color on the cash tax guidance? I think it's a little bit below what we had at least had been anticipating for you guys for this year. Is there anything specific that you can point to? Maybe how should we think about cash taxes on a go-forward basis? Yeah. Thank you for the question. Yes, a couple things lined up for us for 2023. One of them was that we had better than expected GW from our Great Western acquisition cost allocations, which increased our deductibility in 2023. We also did not have any limitations after doing finalizing our analysis on Great Western NOLs. We also did not fall into the new IRA, rules that have been put out, but that will impact us in 2024. Finally, with the lower commodity prices, the, NOLs that we have outstanding existing are just gonna be more fully utilized in 2023. In a long way, we had a bunch of stars that lined up for us that are really materially lowering our 2023 tax bill. However, we will not be able to take those advantages, and we will likely be in the IRA category in 2024. I can give a more firm update on 2024 cash taxes probably in about 90 days, as we're still formalizing a few things as we've wrapped up 2023. I would give you this guidance, the 15%-18% of pre-tax free cash flow for 2024 is probably a good number, as I think we'll fully exhausted, what's left in our cabinet to use in 2023. Hopefully that helps. 2023 should be fairly minimal, but 2024 should be more material, probably what you were expecting for 2023. Awesome. Yeah, Scott, that's great, color and super helpful. Maybe, switching gears now, maybe for Lance, just as we think about inventory, and I guess particularly in the Permian, you guys noted maybe just three years left or so of core economic inventory. Maybe there's some upside to that number through exploration. Just how should we think about the Permian moving forward? I think maybe at one point there was discussions around potentially selling the asset, but how do we think about that in the portfolio and then, you know, whether or not we should always assume PDC prefers a two-basin strategy? Thanks, guys. Yeah. Thanks, Gabe. I appreciate that. Good question there. You know, we really sit back strategically and really, you know, think that having a presence in two basins is very important for future value creation for the company. When we look at our Delaware position, we're very thankful for that position. As you can see, we're working on ways on our existing position to grow that inventory, not only the 60 core locations, but the additional 40 that we're testing up with the Wolfcamp C and the Third Bone Spring Carb Shale that we're gonna be testing this year. You know, so Gabe, our teams continue to look for ways, what I would call it blocking and tackling, where we can, you know, trade with other parties or put a section together with another company and drill two milers versus one milers. Always continue to look for those opportunities that we think are important to continue to, you know, grow the inventory and make it sustaining. you know, let's say this, you know, as we test the 40, you know, contingent locations, you know, if those do work in a manner that fits with us and the price for gas, you know, comes together, you know, then we're probably adding another, you know, two, three years to our inventory, you know, with a one-rig pace and all. That by itself is sustaining for us. We like how that fits and presents itself. You know, and then, of course, on the inventory building side from, you know, the acquisition standpoint, you know, we have a very, methodical, disciplined process that, you know, we'll look at opportunities where it has to fit all of our criteria to bring on some additional locations, you know, through our processes that, you know, creates long-term value for shareholders. We continue to look at that, but we're patient. We do have a longer runway, especially with the contingent locations coming in. We'll continue to be thoughtful how we look at this and always, you know, follow our, you know, methodical acquisition approach. That's great color. Thanks a lot, Lance. Thanks, guys. One moment for our next question. Our next question comes from Arun Jayaram of JP Morgan, your line is open. Yeah, good morning. I wanted to see if you could provide a little bit more insights on your 2023 program at the Wattenberg Field. I think you guys have, you know, highlighted just over 200 TILs this year. Can you give us a sense of between the four areas that you highlighted on slide eight, the general mix of activity between, you know, the black oil, north/south, light oil and retrograde condensate parts of the field? Yeah. I mean, I could just jump in here. Actually I jumped to slide nine. The reason why I'm jumping to nine, you can see that almost all of our wells that we'll be turning on in 23 are DUCs as they enter 23. When you look at it, you can see that we're hitting all of the areas. I'd say, you know, probably 90% of our turning lines are gonna be from those DUCs. I think it's pretty representative across the different areas that we have. That's helpful. Just my follow-up. On slide 12, you know, you provide a lot of detail around your, you know, a representative of your expected productivity over the next kind of five years. I was wondering if you could, you know, give us a sense of your oil productivity you expect to be relatively flat per foot. As we think about, like, your longer term growth rate of the company, do you expect to be completing more footage over this kind of five-year window? Is a higher mix of called wells in the Guanella CAP area, is that what's driving the overall higher productivity as we get into 2025 and 2026? Yeah. I would say there could be some small increases in footage, but what we're really trying to point out here as we're going through this is when you really look at the Guanella CAP A lot of it is going to be in that light oil and the retrograde gas, especially when we are in those retrograde gas, it is really just adding a lot of natural gas and NGL liquids to the portfolio mix. The oil is staying relatively consistent. From one standpoint, you could say, "Hey, look, they are looking like a gasier company from a percent of mix of total, but oil is staying relatively consistent." What you could see once we get there in 2024 to 2025, oil being more flattish and gas and NGLs growing a little bit higher%. We want to make sure we are clear the oil is going to still be there, and it is not oil is going down and gas and NGLs are going up. It is that oil is being maintaining its production while gas and NGLs are probably growing a little bit per well, which still leads to great economics. Right. Is the read-through from this slide is that in 2024, that your oil production should stay relatively flat on a year-over-year basis, but maybe your BOEs is down a touch? No, I don't, I don't think that's the goal, Arun. This is Bart. Okay. I think, obviously the 2024 plan still has a lot of polish, I think overall production growth, modest oil growth are still the goals for us. Okay. There's a lot of levers we can pull to achieve that. That's correct. Great. Thanks a lot, gentlemen. One moment for our next question. Our next question comes from Umang Choudhary of Goldman Sachs. Your line's open. Hi, good morning, and thank you for taking my questions. Also thank you for the update on the DJ Basin inventory and the multi-year development plans. I guess two follow-up questions on this point. One, you indicate that you have permits for 53% of your current undeveloped inventory in the higher return light oil window. You talked about applying for additional permits in this window. Any color you can provide on timing? Then, just wanted to quickly get your thoughts around the longer lateral development as well and how and if, and the impact it has to your capital efficiency in the area. Dave, can you provide color on? Yeah. next year or two's Yeah ... additional permits and then the longer laterals? The lighter oil window that you're describing is predominantly our CAP area. You know, it's the retrograde gas and the lighter oil in our CAP area. Currently, we have 200 DUCs. We have 380 permits in hand. We have 450 in this CAP area that we're talking about now, and then we have more OGDPs in process for the, for the half of the permits for our inventory. As we continue to look at our drilling programs, the longer laterals will continue to increase, really focusing on 2 miles and 3-mile laterals going forward. There's just so many more advantages to larger pads, more wells per pad, sharing facilities and drawing those longer laterals from an economic standpoint. Dave, just one other point I think to touch on this comment was, you know, when you look at that light oil and there's still 47% left to permit, we can't really go permit all that today in OGDPs because we couldn't drill it all by the time that this five-year window was up. The rest of those areas, that 47%, especially in the light oil window, that'll be permitted over the next, I'm guessing, Dave, probably 2-3 years max, because then they have a three-year shelf life, which will take us into our 2028, 2029 kind of activity. Is that fair? That is fair. When you think about OGDPs, just remember they're good for three years. You don't wanna get too far over your skis and have them permitted and not be able to drill them within that three-year window. Now, the CAP is a 10-year window, and we're strategically planning that with infrastructure and all the other things associated with that CAP right, at this point. Great. That's really helpful. I guess from a follow-up, just wanted to get your thoughts around your free cash flow allocation plans for this year. How should we think about the balance between the payment of $370 million, which is currently drawn on the revolver, and then the upside to the 60% post-dividend free cash flow towards capital returns? Again, share repurchase is gonna be the primary vehicle. I would say that, you know, that's our number one when we're looking through this. We're gonna keep monitoring. We're gonna pace ourselves, so we're buying back shares throughout the entire year. You know, the special dividend is only if we need to top it off, but if we can do all 60+% through the share repurchases, that's the goal. That's what we're gonna try to achieve. The remaining 40%, yeah, there's some more flexibility to do some more share repurchase, but also paying down a little bit of debt, I think is important as well, you know. We'll manage it throughout the year, but I expect debt to go down $100 million-$200 million throughout the year. You know, we're ultimately over the next couple of years trying to get that debt down to around that $800 million level, but the shareholder returns is still our first priority as we're very comfortable where our debt balance and debt levels are right now. Got it. Very clear. Thank you. One moment for our next question. Our next question comes from Bertrand Donnes of Truist. Your line is open. Good morning, guys. I think you just kind of brushed on the buyback strategy that you're still, you know, focused on that more than higher cash payout. Your year-to-date performance, you know, kind of puts you in the top 10% of the group. You are still trading at a good discount to the group, so there's kind of two sides of the coin there. Maybe I think the prior thought process was you buy back, you know, a lot of your shares, and then the CAP gets approved, and then there's kind of a re-rating, and I think we've seen some of that happening. I'm just wondering, you know, at what point do you kind of wave the victory flag on buybacks and switch to more cash payments, or do you really need to see your multiple, you know, go higher from here? We still think, we still look at the multiples and look at the markets and we don't see a discernible trend between which one. Through talking to our investors, everyone's very supportive on the share buyback. Right now, I think we're gonna stay on that track. I mean, we still think our shares are undervalued. We still think there's room for growth. Yes, it was a big step for us with the CAP approval, but now I think people that haven't been looking at the names are starting to look at our name again and digesting. I still think there's room for us to move north. For now, we're gonna stay with the share buyback approach and look to have an aggressive plan in 2023. That's great. Makes total sense. The follow-up, it's a bit in the weeds. On your CAP, there's a pad called the Windham, I'm trying to read permit lines here, so forgive me if I got it wrong, but it looks like your spacing has about 23 wells in the Niobrara across the section, that seems a little bit tighter than normal. I just wanted to get an update on maybe the Wattenberg spacing goal or maybe there was something special there. Lance, do you. Yeah. Hey, that's a great question. Yeah, sounds good. Good question. As we look at the Wattenberg development as it continues to progress over time, we're essentially sort of in the 20 to 24 well per section spacing per DSU. We've got a lot of data and history that really shows that that's the right spacing, you know, to bring the value out of the DSU itself and deliver exceptionally strong economics. That's what you're seeing in the economics table there as well. There will be a few areas we're going to test something even tighter than that, in a few areas just to see what the potential upside could look like. Keep in mind too that some of those, you know, tighter spacings has us, you know, targeting some of the Niobrara A a s well, and that was one of the things that SRC had done, you know, before PDC and SRC, you know, combined together. That's kind of the general spacing that we have there. It's the spacing that really works well, and it's the basis for all of our type curves and analysis that you're seeing today. Dave, you wanna add a little color to this? Yeah. I think that Windham facility is gonna be drilled at the end of 2024. It came over from, you know, SRC, where they planned a lot of As and Codells. I think it's a, it's a subject of the gun barrel with, you know, the Niobreras, the Codell, and the, and the As being representative in that package. Okay. Well, that sounds good. I mean, if Lynn started it off, I'm sure it's good. Maybe just to follow up is, are there any tighter spacing tests that maybe we should expect? You know, is there any comparison that you'd be able to give towards the end of the year, or is that maybe the primary one? Well, Bert, I think as we go through the next year or two, you can expect what Lance was talking about, the 20-24 for us to continue, especially as we move towards the northern, the northern Black Oil Range area. You're gonna see us test that 24 more and more, okay. Without having all the calendar and the drill schedule in front of me, just expect that to be more information that we will obviously communicate to the market. Yeah. I think there might be some comparisons on those spacings. You know, we're going to start really drilling the Summit area up with the Chalk, the Whitney, the bypass Denali. There could be some good comparisons to look at. As we always evaluate our spacing, and look backs and our production, we'll be able to convey that out to you. That's great. Thanks for the update, guys. One moment for our next question. Our next question will come from Oliver Huang of TPH & Co. Your line is open. Good morning, everyone, and thanks for taking my questions. Really appreciate the details that you all provided on the economics of the various phase windows within your Wattenberg portfolio. Maybe sort of a follow-up to Arun's question from earlier, but just kind of given where spot gas prices are trading at, is there any inclination or even ability to move around some of the more gas-directed drilling towards oilier areas within your program this year? Oliver, I'll tackle that and Dave can add flavor. I think the general answer is no. The way our planning process in the basin, the permit process, the electrification systems that we have, and the acreage as we permit it, we wanna go in and call it, I think we use the term mow the lawn. We want to start at one corner of the acreage and move to the other to optimize the parent-child. There are no parent-child impacts by doing it that way, okay? I think the team has done a phenomenal job in their planning. The thing to just remind you, going to one of the slide that Dave presented, the oil content per lateral foot on those reserves is pretty consistent, and the gas is all incremental revenue. The economics, even in poor gas prices, are incredibly strong. They probably still improve on the gas year wells. I can assure you that the value we're delivering to the shareholders with the drilling programs is phenomenal. I don't think we have a lot of flexibility in the drilling program the way it's laid out. Dave, did I? Yeah, that's exactly right. When we plan this out, you know, it kind of falls in place with our permits in hand. As Bart said, mowing the lawn, where we continue, one rig will be in the Range area, drilling ahead. The other one will continue to drill in Kersey. The other one will be in our in our CAP-type area in the Summit area. Any changes really to our drill schedule at this point. There's slight modifications we can do to push if we need to. Really, it's kind of set in stone, and it's a very methodical plan at this point. Oliver, the other thing to remember, and for everyone on the call, some of the emission reductions that I talked about entail electrification, obviously gas pipelines, but water pipelines and oil pipelines. All that infrastructure is preplanned, and that's fairly significant planning also. For us to say we're gonna drill one area and move and go drill another area creates a disruption in the planning process. It's just another component of the complexities in the Wattenberg in the planning. Okay. That all makes sense. Just for a second question, I didn't see any specific cadence color for the back half of the year yet. Just kind of wondering if we might be able to get some more incremental color there on anything out of the ordinary in terms of, maybe any large batch of wells, coming online late in the year that's largely non-productive for 2023 that would potentially put you all on pretty strong footing when thinking about exiting the year and heading into 2024. Yeah. I mean, our From what I've messaged before, we really haven't changed anything. Just think of it this way. In the second quarter, as I've said on the call today, our capital to midpoint's down about $75 million, and that's because your Delaware completion crew and the second Wattenberg completion crew are going down. The third quarter, we really only have 1 completion crew running. That's the Wattenberg completion crew, and that comes back in the fourth quarter. If you look from a CapEx standpoint, third quarter should be a step down from the second quarter, and fourth quarter should be a step up from the third quarter. From a production standpoint, obviously, we've given you the first 2 quarters. Third quarter will remain strong as we're still getting peak production from our Delaware properties that we're turning on and the turn-in-line program from the Delaware. The fourth quarter probably steps down a bit from the third quarter, as we don't get much benefit from that second Wattenberg crew until 2024. Hopefully that'll help you give a little bit of curve and shape to the numbers and delivers confidence in our annual goals. Awesome. Thanks for the time, guys. One moment for our next question. Our next question will come from Nicholas Pope of Seaport Research. Your line is open. Morning, everyone. Morning. Morning. I was hoping maybe we could quantify a little bit, something you commented on, Bart. You're kind of mentioning progressing more and more 2 mi, 3-mi laterals. Maybe talk a little bit about that progression, like where maybe 2022 was on average, what you're expecting 2023 to look like in terms of the size of these wells that you're targeting in the DJ? Dave, do you have more color on that? You know, I would say just in general terms, we're really targeting 2 mi laterals in the Wattenberg. We've had some 3-mi packages both on the Wayne, which are producing very well. We have a Spinney package coming up here later this year that we're gonna be drilling, and that's another eight wells on 3-mi laterals. We also have a plan to test the limits of what we can drill on another package called the Hand, where we're gonna take two wells, and we're going to really try to drill longer laterals in that area, and we'll see how that goes. There's another- Dave, when you say longer laterals, are we gonna try to exceed three? Is that... On the K2 package, we're on a couple wells. We're going to try to exceed 3 and really target 4-mi laterals. We're going to watch our torque and drag, and if we can get to 4 mi, we're going to test and run casing. If we can't, anything past 3, we'll be very satisfied in that. We will be testing the outer limits of what we can really be drilling. Really our predominantly target are 2 mi laterals right now, moving to 2.5, moving to 3 where we can. We did that on the CAP where we had outlined out as a development plan for 2 mi laterals, and at the last minute before we went in for our application, we changed some of those packages to 3 mi based on the Wayne results that we were getting. We continue to look to drill further and further and, you know, the economics get better and better because you don't have your steel costs and the technology with rotary steerables right now is just doing phenomenally well for us. Yep. Nick, it's you know, to put it in kind of high level, the drill team and the operating team have you know, a day to add that incremental 5,000 feet of drilling. We obviously have the steel and the cement work and the completion. Incrementally, the reserves you add relative to the capital, it drives your drilling F&D down, it drives your IRR on the project up. It reduces the amount of surface you need to extract reserves, which is big in Colorado today. And it also centralizes those reserves on one location for all of our facility design and emission controls that we go through. All of it points towards just making us better, cleaner, more efficient, going forward. These are the things we will continue to test, and they make sense for our investors, and they make sense for the environment. It's part of what we need to be doing to keep driving value. Got it. Should be fun to watch the 4-mi lateral. Kind of as a follow-up here, you know, looking at kind of this mix of the subsurface that y'all broke out, just kinda curious where things stand right now with kind of gas processing, NGL capacity to kinda handle maybe a slight uptick in gas weighting here in the near term. Yeah. haven't heard much worry about that lately. Yeah, Lance will cover this. No, Nicholas Pope. Very good. I appreciate it. Good question. Because we are moving into the CAP area, it's a higher GOR, very valuable wells. What we've done is we've spent a lot of time working kind of, you know, side by side with DCP Midstream, discussing the growth from our overall basin and working with them. They've done a wonderful job of, you know, both with compression in the field, and with, you know, plans to continue to expand their infrastructure in order to, you know, utilize and capture, if you will, all of the growth that we have from our production. The good news is that where we sit today, the line pressures are good, things are very solid in the field. As we project out, you know, five years even, and provide them some really long-term forecasts, you know, we are working very closely with them, and they have various infrastructure expansions in mind in order to meet the growth of our production from the field. I would classify that as working very well for the company, and we have good long-term plans there. As far as takeaway out of the basin, there's more than ample takeaway for natural gas as well as NGLs out of the basin. That's another part of the chain, if you will, that we stay close to them with. We're, we're thankful for how that works and all the way down to the Gulf Coast, for frack space and all for, you know, our NGLs also. You know, from the field all the way down to the market, you know, we feel we're in a pretty good spot where that sits. More to go, but we're staying right in lockstep with them and sharing our plans so that they can be prepared. All right. That's great. Well, thanks, everyone, for the time. I really appreciate it. One moment for our next question. Our next question comes from John Abbott at Bank of America. Your line is open. Hey, good morning, and thank you for taking our questions. Just a few quick ones from me. You know, how are you sort of thinking about hedging now into 2024? We really don't change our philosophy. Again, we look to protect the company from a, from the downside case. We're really trying to protect the cash flows. Our percentage that we actually hedge moderates with the amount of debt that we have on the books. I would just say, generally speaking, we continue to layer in some hedges over time, but at the same time, with our debt balance coming down, we don't feel like we have to be hedged nearly as much as we were prior years. From a percentage standpoint, I would say look for us to be a little bit less hedged than we were in the prior years. We'll continue opportunistically to layer some in and make sure we're protecting the balance sheet in 2024 and 2025. Appreciate that. Then for our follow-up question, it's not your plan as you do pursue growth, but where do you see long-term maintenance CapEx in the DJ? Long-term maintenance CapEx is... $1 billion. Yeah. One, somewhere around there. I mean. Yeah. I mean, we're growing 3%-5% now as a company, so I mean, we're not that far away. My best estimate is, as you're going through this, would be somewhere between that billion. Yeah. 1 was probably my guess. Yeah, I'm probably in the same range, just thinking through this. We also have, you know, some non-production related capital built into our $1.4. Yeah. You gotta peel that out. You have to say, what does it take to keep it flat basically for a few years? Yeah. Yeah, we're probably in that 1.1 range, maybe a little higher. I appreciate. Thank you for the color. Our next question comes from Noel Parks of Tuohy Brothers Investment Research. Your line is open. Hi. Good morning. Morning. Morning. Apologize if you touched on this already. I just wondered. Well, in the current environment where we're seeing oil and gas prices diverge again in sort of a bit of deja vu from some past cycles, do you have any updated thoughts on the outlook for the NGL market specifically? Lance, you wanna cover this? Yeah. You know, I think where we sit right now in NGLs, you know, with propane storage, you know, filling up, we've seen some pressure on propane prices. We've seen some pressure on NGL prices as well. I think, you know, a lot of the NGLs, you know, prices are tied to weather, to, you know, agriculture. It's also tied to kind of the overall, you know, growth of the country as well, you know, over time. I think, you know, look for 'em to kind of be in the range we're sort of seeing right now, sort of, you know, for PDC, sort of what we're using for a budget around that $20 realized price, which by the way, includes a reduction, you know, for the fees that are paid to DCP Midstream. Around that $20 per barrel in general. Look for it to, you know, hopefully pick back up here with increases in gas, you know, demand, which may be a year or two out. Part of the, you know, the oversupply a little bit on NGLs right now is the fact that natural gas in the country is pretty strong, you know, over 100 BCF per day. There's just more liquids that are being, you know, taken out of the gas, and that supply has increased because of the increase in gas volume. You know, look for the continued, you know, focus on, you know, how NGL prices and then are being, you know, are based upon the supply and demand of natural gas and then the overall, you know, growth of the country, you know, through that time. It may be a little bit, another year or two before we see some strength in the NGL prices. You know, that's something we'll continue to monitor, you know, as we go forward here. Okay, great. Thanks a lot. I'm showing no further questions at this time. I would now like to turn the call back to Bart Brookman, and that's President and CEO for closing remarks. Yeah. Thank you, Tanya, and thank you everyone, for those who are still on the call, for joining us today. Hopefully we provided, some good color on the quality of our plan and our inventory and, our outlook, not only for 2023 but future years. Appreciate you joining. Ladies and gentlemen, this concludes today's conference. Thank you for your participation. You may now disconnect.