PDC Energy, Inc.

Good day, and thank you for standing by. Welcome to the PDC Energy fourth quarter 2022 conference 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 11 on your telephone. You will then hear an automated message advising that your hand is raised. To withdraw your question, please press star 11 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 Vandepoort, Director of Investor Relations. Please go ahead.

Thank you, and good morning, everyone. On today's call, we will have President and CEO Bart Brookman, Executive Vice President Lance Locke, Chief Financial Officer Scott Myers, 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 the actual results to differ materially from forward-looking statements, 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.

Thanks, Erin, and 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, a billion dollars of which was returned to our shareholders in the form of share repurchases, our fixed dividends, and a $0.65 per shared 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 and 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. And drill permits. I want to extend the most sincere thank you to our regulatory group, permit specialists, land team, operations, and air compliance groups. In 2022, we cracked the code on obtaining permits in the state of Colorado. And through our approved OGDPs, and Great Western Acquisition, we now have permits and ducks 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 a 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, and a permit life of 10 years. Technically, we are implementing significant best business practices, including deploying more two- to three-mile 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. And 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. And 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 40 cents per share, and expanding our buyback authorization by $750 million, both demonstrate the company's commitment to shareholder returns. And last for my comments today, a 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. Now, I'll turn the call over to Lance Locke for an update on the company's reserves and inventory.

Thanks, Bart. Slide 7 highlights our 2022 year-improved reserves, which increased to approximately 1.1 billion barrels of oil equivalent. This increase represents 35% compared to our year-end 2021 approved reserves. 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 approved reserve replacement of 440 percent in 2022 equally important we generated approximately 220% approved 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 improved reserves generated a pre-tax PV10 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 decline by approximately 2% from the SEC price case. This, again, is another measure of the highly economic nature of our Tier 1 asset base. Moving now to slide 8. I want to take a moment and provide some additional detail on our best-in-class Tier 1 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, but in order to more clearly describe our Tier 1 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 ducts in the Wattenberg field. As shown on this 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 Gwinella 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. So 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 Blackwell Range acreage area that we acquired from Great Western. While it's 100% permitted, we want to note that our teams are working on various inventory expanding opportunities that was not included in the original transaction. Our least permitted acreage is in the Blackwell window in the north, but 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 the slide highlights our per-well reserves for our two-mile 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. While 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 to 96% internal rates of return based on $75 oil and $3 gas. As we start development of our Grinnelli 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 in economics in the company's inventory. These two windows generate an average rate of return on two-mile 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 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 want to 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 want to 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 want to 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-octa 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, and an all-in GNA 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 spud 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 work over 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 work over activity during the quarter. Moving to slide 12, I want to 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. Our Wattenberg assets has industry leading economics and years of tier one inventory development mapped out before highlighting the longer term outlook in the basics. I want to provide an update on our 36 well gusts 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 pads where acreage supports can reduce surface footprint and the impact to communities while driving efficiencies. Production from these 60 plus 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 one 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 want to 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 or 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 want to provide a brief update on the Delaware asset. During the quarter, we ran one to two work over 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 and 2023 is preliminary focused on continuing develop of the Wolf Camp A and B zones. We will also evaluate opportunities in the Wolf Camp C and Third Bone Springs 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 ducts 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 Myers.

Thank you, Dave. Starting on slide 15, and as has already been pointed out on the call, 2022 was an exceptional year operationally for PDC, and 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, exclusives of the approximate 22 cents 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, 35 cent base dividend, and 65 cent 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 want to 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 0.5 times. 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 want to 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 plus percent 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% to 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 to $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 40 cents per share announced last week, we've already committed 118 million of returns during the first quarter. Finally, on slide 19, I want to provide more detailed guidance for 2023 and the first half of the year. we anticipate 2023's capital investments of $1.35 to $1.5 billion, which generates between 255,000 to 265,000 VOE per day and 82,000 to 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 to 225 wells. The capital budget also includes non-ops, 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 proof. We plan to spot and complete approximately 15 to 25 wells in 2023. In the first quarter, the company expects to invest between 400 and 475 million, with total production being in the range of 240 to 255,000 BOE per day and 78 to 84,000 barrels per day of oil production. In the second quarter, the company plans to invest between 325 and 400 million and total production to be in the range of 257 to 272,000 BOE per day and 84 to 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 proof 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 11 on your telephone and wait for your name to be announced. To withdraw your question, please press star 11 again. one moment while we compile the Q&A roster. And our first question will come from Gabe Dowd of Cohen. Your line is open.

Thank you. Hey, everybody. Thanks for all the prepared remarks and for picking 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 at least have been anticipating for you guys for this year. Is there anything specific that you can point to? And 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. And then we also did not fall into the new IRA rules that have been put out, but that will impact us in 2024. And finally, with the lower commodity prices, the NOLs that we have outstandingly existing, are just going to be more fully utilized in 2023. So 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 24. So I can give a more firm update on 24 cash taxes probably in about 90 days as we're still formalizing a few things as we've wrapped up 23. But I will give you this guidance, the 15 to 18% of pre-tax free cash flow for 24 is probably a good number as I think we'll fully exhausted what's left in our cabinet to use in 23. So hopefully that helps. 23 should be fairly minimal, but 24 should be more material, probably what you were expecting for 23. Awesome.

Yes, Scott, that's great color and super helpful. So 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, and maybe there's some upside to that number through exploration. But 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 set back strategically and really, you know, think that having, you know, presence in two basins is very important. you know, for future value creation for the company. And so, you know, when we look at our Delaware position, we're very thankful for that position. And 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 Wolf Camp C and the third bone spring carb shale that we're going to be testing this year. So Gabe, our teams continue to look for ways, what I would call a blocking and tackling where we can trade with other parties or put a section together with another company and drill two milers versus one milers. So always continue to look for those opportunities that we think are important to continue to grow the inventory and make it sustaining. And let's say this, as we test the 40 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, couple, three years to our inventory, you know, with a one rig pace and all. So that by itself is sustaining for us. We like how that fits and presents itself. So, you know, and then, of course, on the inventory building side from, you know, sort of the acquisition standpoint, you know, we have a very, you know, methodical discipline process that, We'll look at opportunities where it has to fit all of our criteria to bring on some additional locations through our processes that create long-term value for shareholders. So we continue to look at that, but we're patient. We do have a longer runway, especially with the contingent locations coming in. And so we'll continue to be thoughtful how we look at this and always follow our methodical acquisition approach.

No, that's a great call. Thanks a lot, Lance. Thanks, guys.

One moment for our next question. And our next question comes from Arun Jayaram of JPMorgan.

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... highlighted just over 200 tills 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 the black oil and 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. And the reason why I jumped to nine, you can see that almost all of our wells that we'll be turning on in 23 are ducts as they enter 23. So 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 going to be from those ducts. So I think it's pretty representative across the different areas that we have.

That's helpful. And 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. And I was wondering if you could, you know, give us a sense of your oil productivity you expect to be relatively flat per foot. But 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, and is a higher mix of wells in the Guinella cap area, is that what's driving the overall higher productivity as we get into 25 and 26?

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 Guinella caps, A lot of it's going to be in that light oil and the retrograde gas. Especially when we're in those retrograde gas, it's 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're looking like a gassier company from a percent of mix of total, but oil is staying relatively consistent. So what you could see once we get there in 24 to 25, oil being more flattish and gas and NGLs growing a little bit higher percentage, but we want to make sure we're clear the oil is going to still be there and it's not oil is going down and gas and NGLs are going up. It is that oil is being maintained in its production while gas and NGLs are probably growing a little bit per well, which still leads to great economics.

Right. And is the read through from this slide is that in 2024 that your oil production state should stay relatively flat on the year of your basis, but maybe your BOE is down a touch?

No, I don't think that's the goal of room. This is I think obviously the 24 plan still has a lot of a lot of polish, but I think overall production growth, modest oil growth are still the goals for us.

Okay.

And 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. And our next question comes from Yumeng Chowdhury of Goldman Sachs. Your line's open.

Hi, good morning, and thank you for taking my questions. And 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? And then I just wanted to quickly get your thoughts around the longer lateral development as well and the impact it has to your capital efficiency in the area.

So, Dave, can you provide color on the next year or two's additional permits and then the longer laterals?

So, the lighter oil window that you're describing is predominantly our cap area. It's the retrograde gas and the lighter oil in our cap area. Currently, we have 200 ducts. 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 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 two miles and three 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.

And Dave, just one other point I think to touch on this comment was, 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 at 47%, especially in the light oil window, that'll be permitted over the next, I'm guessing, Dave, probably two, three years max because then they have a three-year shelf life. which will take us into our 28, 29 kind of activity. Is that fair?

That is fair. So when you think about OGDPs, just remember they're good for three years, so you don't want to 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 at this point.

Great, that's really helpful. And I guess for my follow-up, I just wanted to get your thoughts around your free cash flow allocation plans for this year, and 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-evident free cash flow towards capital returns?

Yeah, again, share repurchase is going to be the primary vehicle I would say that 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. The special dividend is only if we need to top it off, but if we can do all 60 plus percent 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. So we'll manage it throughout the year, but I expect debt to go down 100, 200 million throughout the year. Again, 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.

And our next question comes from Bertrand Downs of Truist. Your line is open.

Good morning, guys. I think you just kind of brushed on the buyback strategy that you're still focused on that more than higher cash payout. But your year-to-date performance kind of puts you in the top 10% of the group, and 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 so i'm just wondering you know at what point do you kind of wave the the victory flag on buybacks and switch to more cash payments or or do you really need to see your multiple you know uh go higher from here yeah we still think uh we still look at the multiples look at the markets and and we don't see a discernible trend between

which one, and through talking to our investors, everyone's very supportive on the share buyback. So right now, I think we're going to 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. So I still think there's room for us to move north. So for now, We're going to stay with the share buyback approach and look to have an aggressive plan in 2023. That's great.

It makes total sense. And then the follow-up, it's a bit in the weeds. On your cap, there's a pad called the Wyndham, and 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 NIO across the section, and that seems a little bit tighter than normal. So I just wanted to get an update on maybe the Wattenberg spacing goal or maybe there was something special there.

Yeah, hey, that's a great question. Yeah, sounds good. Good question. So as we look at the Wattenberg development as it continues to progress over time, we're essentially sorting the 20 to 24 well per section spacing per DSU. And we've got a lot of data and history that really shows that That's the right spacing to bring the value out of the DSU itself and deliver exceptionally strong economics. And 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. And keep in mind, too, that some of those tighter spacings has us targeting some of the Niobrara A as well. And that was one of the things that SRC had done before PEC and SRC combined together. So that's kind of the general spacing that we have there. And it's the spacing that really works well. It's the basis for all of our type curves and analysis that you're seeing today.

Dave, you want to add a little color to this?

Yeah, I think that Wyndham facility is going to be drilled at the end of 2024. It came over from you know, SRC, where they planned a lot of A's and CODELs. So I think it's a subject of the gun barrel with, you know, the Niobreras, the CODEL, and the A's being representative in that package.

Okay. Well, that sounds good. I mean, if Lynn started it off, I'm sure it's good. And maybe just to follow up is, Are there any tighter spacing tests that maybe we should expect? Is there any comparison that you'd be able to give towards the end of the year, or is that maybe the primary one?

Bert, I think as we go through the next year or two, you can expect what Lance was talking about, the 20 to 24, for us to continue, especially as we move towards the northern black oil area, you're going to see us test that 24 more and more. 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.

I think there might be some comparisons on those spacings. We're going to just start really drilling the summit area up with the chalk, the Whitney, the bypass, Denali. There could be some good comparisons to look at, and as we always evaluate our spacing and lookbacks 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 and Company. Your line is open.

Good morning, everyone, and thanks for taking my questions. I really appreciate the details that you all provided on the economics of the various phase windows within your Wattenberg portfolio, and 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 boiler areas within your program this year?

Oliver, I'll tackle that, and Dave can add flavor, and 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 want to 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. So I think the team has done a phenomenal job in their planning. The thing to just remind you, going to one of the slides that Dave presented, the oil content per lateral foot on those reserves is pretty consistent, and the gas is all incremental revenue. And so the economics, even in poor gas prices, are incredibly strong. They probably still improve on the gas-year wells. And so I can assure you that the value we're delivering to the shareholders with the drilling programs is phenomenal. But 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, 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 cap type area in the summit area. any changes really to our our drill schedule at this point and there's there's small slight modifications we can do to push if we need to but really it's kind of set in stone it's a very methodical plan at this point Oliver the other thing to remember and for everyone on the call some of the emissions reductions that I talked about entail electrification

obviously gas pipelines, but water pipelines and oil pipelines, and all that infrastructure is pre-planned. And that's fairly significant planning also. So for us to say we're going to drill one area and move and go drill another area creates a disruption in the planning process. So it's just another component of the complexities in the Wadenberg in the planning.

Okay. That all makes sense. And just for a second question, I didn't see any specific cadence color for the back half the year yet. So 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 nonproductive 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, from what I've messaged before, we really haven't changed anything. Just think of it this way. In the second quarter, as I said on the call today, our capital at the midpoint is 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 one completion crew running that's the Wattenberg completion crew and that comes back in the fourth quarter so if you look for my 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 two 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. And then 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. So 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.

Good morning, everyone.

Morning.

I was hoping maybe we could quantify a little bit something you commented on, D., You're kind of mentioning progressing kind of more and more two-mile, three-mile 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 two-mile laterals. in the Wattenberg. We've had some three-mile packages both on the wane, which are producing very well. We have a spinny package coming up here later this year that we're going to be drilling, and that's another eight wells on three-mile laterals. We also have a plan to test the limits of what we can drill on another formation called another package called the HEN, where we're going to take two wells and we're going to really try to drill longer laterals in that area. We'll see how that goes.

David, when you say longer laterals, are we going to try to exceed three?

On the K2 package, we're on a couple wells. We're going to try to exceed three and really target four mile laterals now we're going to watch our torque and drag and if we can get to four miles we're going to test and run casing if we can't anything past three will be very satisfied in that so we will be testing the outer limits of what we can really be drilling but really our predominantly target are two mile laterals right now moving to two and a half moving to three where we can We did that on the cap where we had them outlined out as a development plan for two-mile laterals, and at the last minute before we went in for our application, we changed some of those packages to three miles based on the weighing results that we were getting. So we continue to look to drill further and further, and 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, but 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. So all of it points towards just making us better, cleaner, more efficient going forward. So these are the things we will continue to test, and they make sense for our investors, and they make sense for the environment, and it's part of what we need to be doing to keep driving value.

Got it. Should be fun to watch for my lateral. The – Kind of as a follow-up here, you know, looking at kind of this mix of the subsurface that you all broke out, I'm just kind of curious where things stand right now with kind of gas processing and GL capacity to kind of handle maybe a slight uptick in gas waiting here in the near term. And I just haven't heard much worry about that lately. Yeah, Lance will cover this.

Yeah, no, Nick. Yeah, very good. I appreciate it. Good question. Because we are moving into the cap area, it's a higher GOR, very valuable wells. So 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 base and working with them. And 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 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 five years even and provide them some really long-term forecasts, we are working very closely with them. 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 that 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 thankful for how that works and all the way down to the Gulf Coast for frac space and all for 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 fits. 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 of 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 the downside case. We're really trying to protect the cash flows And our percentage that we actually hedge moderates with the amount of debt that we have on the books. So 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 year. So from a percentage standpoint, I would say look for us to be a little bit less hedged than we were in the prior years. but we'll continue opportunistically to layer some in and make sure we're protecting the balance sheet in 24 and 25.

Appreciate that. And 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...

billion one one somewhere around there I mean I mean we're growing three to five percent now as a company so I mean we're not that far away but I know my best estimate is you're going through this would be somewhere between that billion to one one was probably my guess and 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 you got to peel that out

then you have to say what does it take to keep it flat basically for a few years. And, yeah, we're probably in that 1.1 range, maybe a little higher.

I appreciate it. Thank you for the call.

And our next question comes from Noelle Parks of Truie Brothers Investment Research. Your line is open.

Hi, good morning. I apologize if you touched on this already, but I just wondered, can you talk, well, in the current environment where we're seeing oil and gas prices diverge again in sort of a bit of deja vu for some past cycles, do you have any updated thoughts on the outlook for the NGL market specifically?

Lance, you want to 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 you know, the overall, you know, growth of the country as well, you know, over time. So I think, you know, look for them 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. So around that $20 per barrel in general. But look for it to, you know, hopefully pick back up here with, increases in gas demand, which may be a year or two out. So part of the oversupply a little bit on NGLs right now is the fact that natural gas in the country is pretty strong, over 100 BCF per day. So there's just more liquids that are being taken out of the gas, and that supply has increased because of the increase in gas volume. So, you know, look for the continued, you know, focus on, you know, how NGL prices 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. So it may be a little bit another year or two before we see some strengthening in the NGL prices. But, you know, that's something we'll continue to monitor, you know, as we go forward here.

Okay, great.

Thanks a lot.

And 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. And hopefully we provided some good color on the quality of our plan and our inventory and and our outlook not only for 23 but future years. Appreciate you joining.

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

The conference will begin shortly. To raise and lower your hand during Q&A, you can dial star 1-1. Thank you. The conference will begin shortly. To raise and lower your hand during Q&A, you can dial star 1 1. Thank you. you Bye. Thank you.

Good day, and thank you for standing by. Welcome to the PDC Energy Fourth Quarter 2022 Conference 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 1-1 on your telephone. You will then hear an automated message advising that your hand is raised. To withdraw your question, please press star 1-1 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 Vandivert, Director of Investor Relations. Please go ahead.

Thank you, and good morning, everyone. On today's call, we will have President and CEO Bart Brookman, Executive Vice President Lance Locke, Chief Financial Officer Scott Myers, 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-US GAAP financial measures. The appropriate disclosures and reconciliations, including a discussion of factors that could cause the actual results to differ materially from forward-looking statements, 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.

Thanks, Aaron, and 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, a billion dollars of which was returned to our shareholders in the form of share repurchases, our fixed dividends, and a 65 cent per share special dividend in 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 Wadenberg position and 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. And drill permits. I want to extend the most sincere thank you to our regulatory group, permit specialists, land team, operations, and air compliance groups. In 2022, we cracked the code on obtaining permits in the state of Colorado. And through our approved OGDPs, CAP, and Great Western Acquisition, we now have permits and ducks 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, and a permit life of 10 years. Technically, we are implementing significant best business practices, including deploying more two to three-mile 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. And 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. And 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 40 cents per share and expanding our buyback authorization by $750 million, both demonstrate the company's commitment to shareholder returns. And last for my comments today, a 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. Now I'll turn the call over to Lance Locke for an update on the company's reserves and inventory.

Thanks, Bart. Slide 7 highlights our 2022 year-end approved reserves, which increased to approximately 1.1 billion barrels of oil equivalent. This increase represents 35% compared to our year-end 2021 approved 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 approved reserve replacement of 440% in 2022. Equally important, we generated approximately 220% approved reserve replacement through the drill bit, which demonstrates the high quality of our Tier 1 asset base. At the SEC flat price deck of approximately $93 per barrel at $6 gas, our 2022 year improved reserves generated a pre-tax PV10 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 1 asset base. Moving now to slide eight, I want to take a moment and provide some additional detail on our best-in-class Tier 1 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, but in order to more clearly describe our Tier 1 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 ducts in the Wattenberg Field. As shown on this 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 granola 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. So 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 want to note that our teams are working on various inventory expanding opportunities that was not included in the original transaction. Our least permitted acreage is in the Blackwell window in the north, but 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 the slide highlights our per well reserves for our two mile 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. While 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 to 96% internal rates of return based on $75 oil and $3 gas. As we start development of our Grinnelli 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 in economics in the company's inventory. These two windows generate an average rate of return on two-mile 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 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 want to 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 want to 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 want to 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-octa activity, field level efficiencies both on the drilling and completion side of 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, and an all-in GNA 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 spud 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 work over 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 work over activity during the quarter. Moving to slide 12, I want to 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. Our Wattenberg assets has industry leading economics and years of tier one inventory development mapped out. Before highlighting the longer term outlook in the basics, I want to provide an update on our 36 well gusts 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 plus 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 one 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 want to 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 or 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 want to provide a brief update on the Delaware asset. During the quarter, we ran one to two work over 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 and 2023 is preliminary focused on continuing develop of the Wolf Camp A and B zones. We will also evaluate opportunities in the Wolf Camp C and third bone springs 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 ducts 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 Myers.

Thank you, Dave. Starting on slide 15, and as has already been pointed out on the call, 2022 was an exceptional year operationally for PDC, and 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, exclusives of the approximate 22 cents 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, 35 cent base dividend, and 65 cent 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 want to 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 0.5 times. 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 want to 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 plus percent 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 seven to 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 35 cents to 40 cents 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 40 cents per share announced last week, We've already committed 118 million of returns during the first quarter. Finally, on slide 19, I want to provide more detailed guidance for 2023 and the first half of the year. We anticipate 2023's capital investments of 1.35 to 1.5 billion, which generates between 255 to 265,000 BOE per day and 82 to 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 to 225 wells. The capital budget also includes non-ops, infrastructure for a 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 group. We plan to spud and complete approximately 15 to 25 wells in 2023. In the first quarter, the company expects to invest between $400 and $475 million with total production being in the range of 240 to 255,000 BOE per day and 78 to 84,000 barrels per day of oil production. In the second quarter, the company plans to invest between 325 and 400 million and total production to be in the range of 257 to 272,000 BOE per day and 84 to 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 proof 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 11 on your telephone and wait for your name to be announced. To withdraw your question, please press star 11 again. One moment while we compile the Q&A roster. And our first question will come from Gabe Dowd of Cohen. Your line is open.

Thank you. Hey, everybody. Thanks for all the prepared remarks. and for picking 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 at least have been anticipating for you guys for this year. Is there anything specific that you can point to? And 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 finalizing our analysis on Great Western NOLs. And then we also did not fall into the new IRA rules that have been put out, but that will impact us in 2024. And finally, with the lower commodity prices, the NOLs that we have outstandingly existing are just going to be more fully utilized in 2023. So 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. So I can give a more firm update on 24 cash taxes probably in about 90 days as we're still formalizing a few things as we've wrapped up 23. But I will give you this guidance, the 15 to 18% of pre-tax free cash flow for 24 is probably a good number as I think we'll fully exhausted what's left in our cabinet to use in 23. So hopefully that helps. 23 should be fairly minimal, but 24 should be more material, probably what you were expecting for 23. Awesome.

Yes, Scott, that's great color and super helpful. So 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, and maybe there's some upside to that number through exploration. But 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 set back strategically and really, you know, think that having, you know, presence in two basins is very important. you know, for future value creation for the company. And so, you know, when we look at our Delaware position, we're very thankful for that position. And 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 Wolf Camp C and the third bone spring carb shale that we're going to be testing this year. So, Gabe, our teams continue to look for ways, what I would call a blocking and tackling, where we can trade with other parties or put a section together with another company and drill two milers versus one milers. So always continue to look for those opportunities that we think are important to continue to grow the inventory and make it sustaining. And let's say this, as we test the 40 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, couple, three years to our inventory, you know, with a one rig pace and all. So that by itself is sustaining for us. We like how that fits and presents itself. So, you know, and then, of course, on the inventory building side from, you know, sort of the acquisition standpoint, you know, we have a very, you know, methodical discipline process that, We'll look at opportunities where it has to fit all of our criteria to bring on some additional locations through our processes that create long-term value for shareholders. So we continue to look at that, but we're patient. We do have a longer runway, especially with the contingent locations coming in. And so we'll continue to be thoughtful how we look at this and always follow our methodical acquisition approach.

No, that's a great call. Thanks a lot, Lance. Thanks, guys.

One moment for our next question. And our next question comes from Arun Jayaram of J.P.

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... highlighted just over 200 tills 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 the black oil and 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. And the reason why I jumped to nine, you can see that almost all of our wells that we'll be turning on in 23 are ducts as they enter 23. So 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 of our turning lines are going to be from those ducts. So I think it's pretty representative across the different areas that we have.

That's helpful. And 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. And I was wondering if you could, you know, give us a sense of your oil productivity you expect to be relatively flat per foot. But 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, and is a higher mix of wells in the Glenella cap area, is that what's driving the overall higher productivity as we get into 25 and 26?

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 Glenella caps, A lot of it's going to be in that light oil and the retrograde gas, and especially when we're in those retrograde gas, it's really just adding a lot of natural gas and NGL liquids to the portfolio mix. The oil is staying relatively consistent. So from one standpoint, you could say, hey, look, they're looking like a gassier company from a percent of mix of total, but oil is staying relatively consistent. So what you could see once we get there in 24 to 25, oil being more flattish and gas and NGLs growing a little bit higher percentage, but we want to make sure we're clear the oil is going to still be there and it's not oil is going down and gas and NGLs are going up. It is that oil is being maintained in its production while gas and NGLs are probably growing a little bit per well, which still leads to great economics.

Right, and is the read-through from this slide is that in 2024 that your oil production state should stay relatively flat on the year of your basis, but maybe your BOE is down a touch?

No, I don't think that's the goal of room. This is part, I think, obviously the 24 plan still has a lot of polish, but I think overall production growth, modest oil growth are still the goals for us. Okay. And 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. And our next question comes from Yumeng Chowdhury of Goldman Sachs. Your line's open.

Hi, good morning, and thank you for taking my questions. And 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? And then I just wanted to quickly get your thoughts around the longer lateral development as well and the impact it has to your capital efficiency in the area.

Dave, can you provide color on the next year or two's additional permits and then the longer laterals?

The lighter oil window that you're describing is predominantly our cap area. It's the retrograde gas and the lighter oil in our cap area. Currently, we have 200 ducts. 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 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 two miles and three 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.

And 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. So the rest of those areas at 47%, especially in the light oil window, that'll be permitted over the next, I'm guessing, Dave, probably two, three years max because then they have a three-year shelf life which will take us into our 28, 29 kind of activity. Is that fair?

That is fair. So when you think about OGDPs, just remember they're good for three years, so you don't want to 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 rent at this point.

Great, that's really helpful. And I guess for my follow-up, I just wanted to get your thoughts around your free cash flow allocation plans for this year, and 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-evident free cash flow towards capital returns?

Yeah, again, share repurchase is going to be the primary vehicle I would say that that's our number one when we're looking through this. We're going to keep monitoring. We're going to pace ourselves so we're buying back shares throughout the entire year. The special dividend is only if we need to top it off, but if we can do all 60 plus percent through the share repurchases, that's the goal. That's what we're going to try to achieve. The remaining 40 percent, 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. So we'll manage it throughout the year, but I expect debt to go down 100, 200 million throughout the year. Again, 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.

And our next question comes from Bertrand Downs of Truist. Your line is open.

Good morning, guys. I think you just kind of brushed on the buyback strategy that you're still focused on that more than higher cash payout. But your year-to-date performance kind of puts you in the top 10% of the group, and 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 so i'm just wondering you know at what point do you kind of wave the the victory flag on buybacks and switch to more cash payments or or do you really need to see your multiple you know uh go higher from here yeah we still think uh we still look at the multiples look at the markets and and we don't see a discernible trend between

which one, and through talking to our investors, everyone's very supportive on the share buyback. So right now, I think we're going to 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. So I still think there's room for us to move north. So for now, We're going to stay with the share buyback approach and look to have an aggressive plan in 2023. That's great.

It makes total sense. And then the follow-up, it's a bit in the weeds. On your cap, there's a pad called the Wyndham, and 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 NIO across the section, and that seems a little bit tighter than normal. So I just wanted to get an update on maybe the Wattenberg spacing goal or maybe there was something special there.

Yeah, hey, that's a great question. Yeah, sounds good. Good question. So as we look at the Wattenberg development as it continues to progress over time, we're essentially sorting the 20 to 24 well per section spacing per DSU. And we've got a lot of data and history that really shows that that's the right spacing to bring the value out of the DSU itself and deliver exceptionally strong economics. And 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. And keep in mind, too, that some of those tighter spacings has us targeting some of the Niobrara A as well. And that was one of the things that SRC had done before PEC and SRC combined together. So that's kind of the general spacing that we have there. And it's the spacing that really works well. It's the basis for all of our type curves and analysis that you're seeing today.

Dave, you want to add a little color to this?

Yeah, I think that Wyndham facility is going to be drilled at the end of 2024. It came over from you know, SRC, where they planned a lot of A's and CODELs. So I think it's a subject of the gun barrel with, you know, the Niobreras, the CODEL, and the A's being representative in that package.

Okay. Well, that sounds good. I mean, if Lynn started it off, I'm sure it's good. And maybe just to follow up is, Are there any tighter spacing tests that maybe we should expect? Is there any comparison that you'd be able to give towards the end of the year, or is that maybe the primary one?

Bert, I think as we go through the next year or two, you can expect what Lance was talking about, the 20 to 24, for us to continue, especially as we move towards the northern black oil area, you're going to see us test that 24 more and more. 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.

I think there might be some comparisons on those spacings. We're going to just start really drawing the summit area up with the chalk, the Whitney, the bypass, Denali. There could be some good comparisons to look at, and 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 and Company. Your line is open.

Good morning, everyone, and thanks for taking my questions. I really appreciate the details that you all provided on the economics of the various phase windows within your Wattenberg portfolio, and 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 boiler areas within your program this year?

Oliver, I'll tackle that and Dave can add flavor and 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 want to 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? So I think the team has done a phenomenal job in their planning. The thing to just remind you, going to one of the slides that Dave presented, the oil content per lateral foot on those reserves is pretty consistent, and the gas is all incremental revenue, and so the economics even in poor gas prices, are incredibly strong. They probably still improve on the gas-year wells. And so I can assure you that the value we're delivering to the shareholders with the drilling programs is phenomenal. But 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 cap type area in the summit area. So any changes really to our drill schedule at this point, and there's slight modifications we can do to push if

we need to but really it's kind of set in stone it's a very methodical plan at this point Oliver the other thing to remember and for everyone on the call some of the emissions reductions that I talked about entail electrification obviously gas pipelines but water pipelines and oil pipelines and all that infrastructure is pre-planned and and that's fairly significant planning also so for us to

say we're going to drill one area and move and go drill another area creates a disruption in the in the planning process so it's just another component of the complexities in the waddenburg in the planning okay that all makes sense and just for a second question i didn't see any specific cadence color for the back half the year yet so 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, from what I've messaged before, we really haven't changed anything. Just think of it this way in the In the second quarter, as I said on the call today, our capital at the midpoint is 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 one completion crew running. That's the Wattenberg completion crew, and that comes back in the fourth quarter. So 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 two 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. And then 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. So 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.

Good morning, everyone.

Good morning.

I was hoping maybe we could quantify a little bit something you commented on, Bart. You were kind of mentioning progressing kind of more and more two-mile, three-mile 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 two-mile laterals in the Wattenberg. We've had some three-mile packages both on the Wayne, which are producing very well, We have a spinny package coming up here later this year that we're going to be drilling, and that's another eight wells, three-mile laterals. We also have a plan to test the limits of what we can drill on another package called the HEN, where we're going to take two wells, and we're going to really try to drill longer laterals in that area, and we'll see how that goes.

Dave, are we going to try to exceed three?

So on the K2 package, we're on a couple wells. We're going to try to exceed three and truly target four-mile laterals. Now we're going to watch our torque and drag, and if we can get to four miles, we're going to test and run casing. If we can't, Anything past three will be very satisfied in that. So we will be testing the outer limits of what we can really be drilling. But really our predominantly target are two mile laterals right now, moving to two and a half, moving to three where we can. We did that on the cap where we had them outlined out as a development plan for two mile laterals. And at the last minute before we went in for our application, we changed some of those packages to three miles. based on the weighing results that we were getting. We continue to look to drill further and further and 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.

Nick, to put it in kind of high level, the drill team and the operating team have a day to add that incremental 5,000 feet of drilling. We obviously have the steel and the cement work and the completion. But 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. So all of it points towards just making us better, cleaner, more efficient going forward. So these are the things we will continue to test, and they make sense for our investors, and they make sense for the environment, and it's part of what we need to be doing to keep driving value.

Got it. Should be fun to watch, four-mile lateral. As a follow-up here, looking at this mix of the subsurface that you all broke out, I'm curious where things stand right now with gas processing and GL capacity to handle maybe a slight uptick in gas weighting here in the near term. I haven't heard. much worry about that lately.

Yeah, very good. I appreciate it. Good question and all. Because we are moving into the cap area, it's a higher GOR, very valuable wells. So what we've done is we've spent a lot of time working kind of side by side with DCP Midstream discussing the growth from our overall basin and working with them. And they've done a wonderful job of both with compression in the field and with plans to continue to expand their infrastructure in order to utilize and capture, if you will, all of the growth that we have from our production. And so the good news is that where we sit today, the line pressures are good. Things are very solid in the field. And as we project out 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. So 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. And so we're thankful for how that works and all the way down to the Gulf Coast for frack space and all for our NGLs also. So, 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 of 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 the downside case. We're really trying to protect the cash flows. And our percentage that we actually hedge moderates with the amount of debt that we have on the books. So 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 year. So from a percentage standpoint, I would say look for us to be a little bit less hedged than we were in the prior years, but we'll continue opportunistically to layer some in and make sure we're protecting the balance sheet in 24 and 25.

Appreciate that. And 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... Billion?

One-one? Somewhere around there? I mean, we're growing 3% to 5% now as a company. So, I mean, we're not that far away, but... And my best estimate as you're going through this would be somewhere between that billion to 1.1 was probably my guess.

Yeah, and 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. You've got to peel that out. Then you have to say, what does it take to keep it flat basically for a few years? And, yeah, we're probably in that 1.1 range, maybe a little higher.

Appreciate it. Thank you for the call.

And our next question comes from Noel Parks of True Brothers Investment Research. Your line is open.

Hi, good morning.

Good morning.

I apologize if you touched on this already, but I just wondered, can you talk, 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 want to cover this?

Yeah. I think where we sit right now in NGLs with propane storage 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 NGOs, you know, prices are tied to weather, to, you know, agriculture. It's also tied to kind of the, you know, the overall, you know, growth of the country as well, you know, over time. So I think, you know, look for them 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 the a reduction, you know, for the fees that are paid to DCP midstream. So around that $20 per barrel in general. But 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. You know, so part of the, you know, the oversupply a little bit on NGOs right now is the fact that natural gas in the country is pretty strong, you know, over 100 BCF per day. So there's just more liquids that are being taken out of the gas and that supply has increased because of the increase in gas volume. So look for the continued focus on how NGL prices are based upon the supply and demand of natural gas and then the overall growth of the country through that time. So it may be a little bit another year or two before we see some strengthening in the NGL prices, but you know, that's something we'll continue to monitor, you know, as we go forward here.

Okay, great.

Thanks a lot.

And 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 and Hopefully we provided some good color on the quality of our plan and our inventory and our outlook, not only for 23 but future years. Appreciate you joining.

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