Q4 2022 PDC Energy Inc Earnings Call

February 23, 2023

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

Speaker 1: Good day and thank you for standing by. Welcome to the PDC Energy 4th Quarter 2022 Conference Call.

Speaker 2: 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 Vandepurt, Director of Investor Relations. Please go ahead. Aaron Vandepurt, Director of Investor Relations

Speaker 3: 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 Meyers, and Senior Vice President of Operations Dave Lillo. Yesterday afternoon we issued our press release and posted a presentation that accompanies our remarks today. We also filed our Form 10-K . The press release and presentation are available on the investor relations page of our website at www.pdce.com. On today's call we will reference both forward-looking statements and non-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 2 and the appendix of that presentation. With that, I will turn the call over to our CEO Bart Brookman.

Speaker 4: Thanks, Aaron. Good morning, everyone. Let me open by saying over PDC's entire 50-year history, 2022 stands as the most successful year by almost every measure. A record-free cash flow level of $1.4 billion, a billion dollars of which was returned to our shareholders in the form of share repurchases are fixed dividends in a 65-cent per-shared special dividend in this past December . Production for the company are record 85 million B.O.E. In May, we close the highly-ocreative Great Western acquisition solidifying our already exceptional core-warnberg position in driving solid production and reserve growth. Reserve year end 2022, a 440% reserve replacement for the company, as we grew reserves to 1.1.

Speaker 4: 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. Admissions for the company.

Speaker 4: 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 of energy,

Speaker 4: 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, and a total of

Speaker 4: 22 service locations in 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.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.

Speaker 4: 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 seven highlights our 2022 year improved reserves, which increased 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.

Speaker 4: 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-taxed PV10 value of approximately $19 billion.

Speaker 4: 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 assets base. Moving now to slide 8, I want to take a moment and provide some additional detail on our Best in Class.

Speaker 4: 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 your end...

Speaker 4: 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. All our summit, plains, and cursey areas have three distinct phase windows. Our Grinnellicap acreage is primarily located in the light oil and retrograde gas windows.

Speaker 4: 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 9, 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 derisked our inventory is from a permitting perspective. Overall, our urine inventory of more than 2,100 locations are over 50% permitted, including the cap.

Speaker 3: 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 Black Oil 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 plant our surface locations around.

Speaker 3: We look forward to pursuing these permits in the future. The table on this 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 percent internal rates of return based on $75 oil and $3 gas. As we start development of our Grunella 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.

Speaker 3: 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 a hundred percent and eighty-five percent 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 a highest oil cut at 48%, which still generates approximately 63% rate returns at the same price deck. One final comment. All phased 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.

Speaker 3: 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 BOE or approximately 80,000 BOE per day.

Speaker 5: 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.

Speaker 5: 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 Capitol plans in more detail shortly. During the fourth quarter, our team maintained great focus on managing costs and our LE for the quarter was $3.04 per BLE and an all-ENGNA expense total $1.60 per BLE.

Speaker 5: 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 workover rigs to manage our base operations in the field.

Speaker 5: Production in the Delaware Basin averaged 28,000 BOE per day, of which approximately 39% was oil. LOE in the basin came in at $7.03 per BOE, and is reflective of the continued workover activity during the quarter. Moving to slide 12, I 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 1 inventory development mapped out.

Speaker 5: Before highlighting the longer term outlook in the basin, 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 with our... 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.

Speaker 5: 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.

Speaker 5: Though we have historically and will continue to turn wells in line across multiple phase windows, our oil curve remains very durable.

Speaker 5: 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.

Speaker 5: 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.

Speaker 5: 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 June .

Speaker 5: 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, we have identified approximately 30 core economic locations,

Speaker 5: This represents more than three years of operations. We have also identified approximately 40 contingent additional locations targeting other known zones and locations with shorter laterals that will require improved pricing or additional evaluation before including them in our core inventory count. With that, I will turn the call over to Scott Meyers. Thank you, Dave.

Speaker 5: 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-hedged realized price of approximately $50 per BOE, while operating expenses came in at approximately $8 per BOE. Our G&A came in as expected at approximately $1.60 per BOE, exclusive of the approximate $0.22 per BOE of cost associated with the Great Western acquisition. For the fourth quarter, we generated approximately $260 million of free cash flow. This is quite strong considering the decline in pricing in the fourth quarter and the planned increase in investment tied to adding the second DJ completion crew during the second quarter.

Speaker 5: reducing debt. On slide 17, I want to quickly highlight the continued strength of our balance sheet.

Speaker 5: 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 0.5 times.

Speaker 5: 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.

Speaker 5: 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.

Speaker 5: 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 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.

Speaker 5: 125 wells.

Speaker 5: The capital budget also includes non-ops, infrastructure for a recently approved CAP,

Speaker 5: land, and ESG-related projects. In the Delaware, the company plans to invest approximately 20% of the total capital investments by running a one-rate program and a part-time completion crew. We plan to spot and complete approximately 15 to 25 wells in 2023.

Speaker 5: 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 barrels per day of oil production.

Speaker 5: In the second quarter, the company plans to invest between $325 and $400 million in total production to be in the range of $257,000 to $272,000 BOE per day and $84,000 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.

Speaker 5: 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.

Speaker 2: equivalent to Tier 1 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 1-1 on your telephone and wait for your name to be announced. To withdraw your question, please press star 1-1 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 taking my question.

Speaker 5: Maybe just starting on the 2023 guide, Bart, could you maybe just give us a little bit more color on the cash tax guidance? I think it's a little bit below what we had at least had been anticipating for you guys for this year. Is there anything specific that you can point to and maybe has to rethink about cash taxes on a go forward basis? Yeah, thank you for the question. Yes, a couple of 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.

Speaker 5: 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 outstanding 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.

Speaker 5: 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 have 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.

Speaker 3: How do we think about that in the portfolio and then whether or not we should always assume PDC prefers a two-basin strategy? Thanks, guys. Yeah, thanks, Gab. I appreciate that. Good question there. We really set back strategically and really think that having a presence in two basins is very important.

Speaker 3: for future value creation for the company. And so, when we look at our Delaware position, we're very thankful for that position. And as you can see, we're working on ways under existing position to grow that inventory, now in the 60 core locations, but the additional 40.

Speaker 3: 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 the blocking and tackling, where we can trade with other parties or put a section together with another company and drill two milers.

Speaker 3: in a manner that fits with us and the price for gas comes together, then we're probably adding another couple, three years to our inventory with a one-rig pace and all. That by itself is sustaining for us. We like how that fits and presents itself so quickly.

Speaker 3: You know, and then of course on the inventory building side from you know, so the acquisition standpoint, you know we have a very you know methodical discipline process that you know, we'll look at opportunities where It has to fit all of our criteria to to bring on some additional locations, you know through our through our processes that

Speaker 3: 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 in a methodical acquisition approach.

Speaker 2: Thanks a lot, Lance. Thanks, guys. One moment for our next question. And our next question comes from Arun Jayaram of JP Morgan. Your line is open. Your line is open.

Speaker 6: 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?

Speaker 6: Between the 4 areas that you highlighted on slide 8, 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 can just jump in here and I actually, I jumped to slide 9.

Speaker 6: And the reason why I'm jumping to nine, you can see that almost all of our wells that will be turning on in 23 are ducks as they enter 23. So when you look at it, you can see that we're hitting all of the areas. I'd say... On the running shrunken

Speaker 6: probably 90% of our turn-in lines are going to be from those docks. I think it's pretty representative across the different areas that we have. That's helpful. Just my follow-up, on slide 12, you provide a lot of detail around your representative of your expected productivity over the next five years.

Speaker 6: I was wondering if you could give us a sense of your oil productivity you expect to be relatively flat per foot. But as we think about 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 Grinnell, the cap area, is that what's driving the overall higher productivity as we get into 25? I think so. I can probably can an appropriate Oracle Johannson warranty. I think it comes

Speaker 5: and NGL liquids to the portfolio mix, the oil is staying relatively consistent. So from one standpoint, you could say, hey, look, they're getting a, 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 flat.

Speaker 6: well, which still leads to great economics. Right, and 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 BOEs is down a touch? No, I don't think that's the goal, Rufe. Inno misinformation on the various oil consumption COVID solutions?

Speaker 4: I think obviously the 24 plans still has a lot of polish, but I think overall production growth, modest soil growth are still the goals for us.

Speaker 2: 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 Chaudhry of Goldman Sachs. Your line's open. Hi. Good morning. Thank you for taking my questions.

Speaker 7: 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 have – you indicate that you have permits for 53% of your current undeveloped inventory in the higher return light all window. You talked about applying for additional permits in this window. Any color you can provide on timing?

Speaker 5: 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? So, the lighter oil window that you're describing is predominantly our cap area.

Speaker 5: 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. 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.

Speaker 5: 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, that 47%, especially in the light oil window, that'll be permitted over the next, I'm guessing, Dave, probably two, three, four, five, six months.

Speaker 5: three years max because then they have a three year shelf life which will take us into our 28, 29 kind of activities. 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 ten year window and we were strategically planning that with...

Speaker 7: with infrastructure and all the other things associated with that cap right at this point. Great, that's what you have. And I guess from a follow up, I just wanted to get a thoughts around your free cash flow location 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 there within free cash flow towards capital don'ts. Yeah, again, I share the purchase is going to be the primary vehicle.

Speaker 5: 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.

Speaker 5: I think is important as well. You know, so we'll manage it throughout the year, but I'd expect debt to go down 100, 200 million throughout the year. Again, you know, we're ultimately, over the next couple 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.

Speaker 5: important as well. So we'll manage it throughout the year, but I'd expect debt to go down 100, 200 million throughout the year. Again, we're ultimately over the next couple 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.

Speaker 2: And our next question comes from Bertrand down of truest your line is open. Good morning, guys. I think you just kind of brushed on on the buyback strategy that you're still, you know, focused on that more than higher cash payout. But your year to date performance, you know, kind of puts you in the top 10% of the group and you know, you are still trading at a good discount to the group. So

Speaker 2: there's kind of two sides of the coin there. Maybe I think the prior thought process was you buy back 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 at what point do you kind of wave the victory flag on buybacks and switch to more cash payments or do you really need to see your multiple go higher from here?

Speaker 5: Yeah, we still look at the multiples and look at the markets 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. Right now, I think we're going to stay on that track. 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.

Speaker 5: 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.

Speaker 3: 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 Windham. 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 NYO 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. That's a great question. 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.

Speaker 3: And we've got a lot of data in history that really shows that that's the right spacing, you know, to to bring the value out of the 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, you know, tighter spacings has us, you know, targeting some of the NIBR-A as well. And that was one of the things that SRC had done.

Speaker 5: before PDC and SRC combined together. That's kind of the general spacing that we have there. 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, do 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 SRC where they planned a lot of A's and codels. I think it's a subject of the gun barrel with the Niobrara's, the codel, and the A's being representative in that package.

Speaker 2: Okay, well that sounds good. If Lynn started it off, I'm sure it's good. Maybe just to follow up, 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...

Speaker 4: 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 gonna see us test that 24 more and more, okay? So 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. And I think there might be some comparisons on those spacings, you know, we're going to.

Speaker 2: Our next question will come from Oliver Huang.

Speaker 2: of TPH and Company. Your line is open. Good morning everyone and thanks for taking my questions.

Speaker 8: I really appreciate the details that you all provided on the economics of the various space 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 from the more gas-directed drilling towards oilier areas within your portfolio?

Speaker 4: 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?

Speaker 4: 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 or 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.

Speaker 4: they probably still improve on the gassier 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.

Speaker 5: Yeah, that's exactly right. When we plan this out, it kind of falls in place with our permits in hand.

Speaker 5: As Bart said mowing the lawn where we continue one rig will be in the Range area drilling ahead the other one will continue to drill in Kersey The other one will be in our in our cap type area in the summit area. So

Speaker 5: 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 and it's a very methodical plan at this point. Oliver, the other thing to remember, and for everyone on the call.

Speaker 4: 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 gonna drill one area and move and go drill another area creates a disruption in the planning process. So it's just another component of.

Speaker 8: 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 I was 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.

Speaker 5: Yeah, I mean, I mean, it are 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 to midpoints down about 75 million, and that's because you're Delaware completion crew and the second Watt and Bird completion crew are going down. The third quarter, we really only have one completion crew running, that's the Watt and Bird completion crew, and that comes back in the fourth quarter.

Speaker 5: 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. Hopefully that will help you give a little bit of curve and shape to the numbers and delivers confidence in our annual goals.

Speaker 2: Thanks for your time, guys. One moment for our next question. Our next question will come from Nicholas Pope of Seaport Research. Your line is open. Thank you.

Speaker 2: 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.

Speaker 9: 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.

Speaker 9: 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 there? You know, I would say just in general terms, we're really targeting two-mile laterals. In terms of the bounds that I picture, think it'solt, or w, with the watches, how are the wheelset as we ey hoild.

Speaker 5: 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, three-mile laterals.

Speaker 5: We also have a plan to test the limits of what we can drill on another formation called, or another package called the hen, where we're going to take two wells and we're going to really try to drill.

Speaker 5: longer laterals in that area and we'll see how that goes. There's another... When you say longer laterals are we gonna try to exceed three? Is that...

Speaker 5: So 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.

Speaker 5: We changed some of those packages to three miles based on the lane results that we were getting. We continue to look to drill further and further. The economics get better and better because you don't have your steel costs. The technology with rotary steerables right now is just doing phenomenally well for us.

Speaker 4: 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.

Speaker 4: 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.

Speaker 4: 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...

Speaker 4: 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 the

Speaker 9: As a follow-up here, looking at this mix of...

Speaker 9: of the subsurface that you all broke out. I'm kind of curious where things stand right now with kind of gas processing and GL capacity to handle maybe a slight uptick in gas waiting here in the near term. I just haven't heard much worry about that lately.building

Speaker 9: subsurface that y'all broke out. I'm 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 yeah haven't heard much worry about that lately. Yeah, no, Nick.

Speaker 3: 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, you know,

Speaker 3: 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, you know, five years even and provide them some really long-term forecasts, you know, we are working very closely with them and they have various infrastructure expansions in mind in order to meet the growth of our production from the field. So 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 and so we're thankful for how that works and all the way down to to the Gulf Coast for frack space and all for your NGLs also.

Speaker 9: From the field all the way down to the market, 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 is from John Abbott at Bank of America. Your line is open. Hey, good morning and thank you for taking our questions. Just a few quick ones from me. 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.

Speaker 4: term. and this will be the three Hello

Speaker 5: billion one one, somewhere around there. I mean we're growing three to five percent now as a company, so I mean we're not that far away, but my best estimate is you're going through this, it'll be somewhere between that billion to one one, which is probably my guess. Yeah, and I'm probably in the same range just thinking through this. We also have 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.

Speaker 9: We're probably in that 1.1 range, maybe a little higher. I appreciate it. Thank you for the color. And our next question comes from Noel Parks of True Hi, good morning. I apologize if you touched on this already, but I just wondered, can you talk, well, in the current environment we're seeing oil and gas prices diverge again in sort of a bit of deja vu past cycles.

Speaker 3: Do you have any update thoughts on the outlook for the NGL market specifically? I think where we sit right now in NGL 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 a lot of the NGLs prices are tied to weather, to agriculture. It's also tied to the overall growth of the country as well over time.

Speaker 3: 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 the $20 realized price, which, by the way, includes the 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 NGLs 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, you know, taken out of the gas and that supply has increased because of the increase in gas volume. So, you know, look for the continued 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 through that time. So it may be a little bit, another year or two before we see some strength in the NGL prices, but, you know, that's something we'll continue to monitor, you know, as we go forward here. Thank you.

Speaker 2: 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. 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 us. 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 11.

Speaker 1: you

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

Speaker 10: you

Speaker 10: I I.

Speaker 10: Question.

Speaker 2: 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.

Speaker 2: 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 VandeFert, Director of Investor Relations. Please go ahead. Thank you and good morning, everyone. On today's call, we allow President and CEO , Bart Brookman, Executive Vice President, Lance Locke, Chief Financial Officer, Scott Meyers, and Senior Vice President of Operations, Dave Lillo. Yesterday afternoon, we issued our press release and posted a presentation that accompanies our remarks today. We also filed our Form 10-K . The press release and presentation are available on the Investor Relations page of our website at www.pdce.org.

Speaker 9: 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 VandeFert, Director of Investor Relations. Please go ahead. Aaron VandeFert 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.

Speaker 4: 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, 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 this past December . Replacement for the company, a record 85 million BOE. In May, we closed a highly accretive Great Western acquisition, solidifying our already exceptional core Waddenberg 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 BOE. 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.

Speaker 4: 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 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.

Speaker 4: 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.

Speaker 4: 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. The 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.

Speaker 4: 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.

Speaker 3: SEC price case.

Speaker 3: This again is another measure of the highly economic nature of our Tier 1 assets 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.

Speaker 3: 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 2100 core economic locations, inclusive of 200 ducts in the Wattenberg Field. As shown on the slide, our locations encompass four

Speaker 3: 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. All our summit, plains, and cursey areas have three distinct phase windows. Our Grinnellicap 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 9, we provide a detailed breakout of our approximately 2100 locations by phase window.

Speaker 3: Before touching on the economics, I want to point out how the risk our inventory is from a permitting perspective. Overall, our year in inventory of more than 2100 locations are over 50 percent 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 Agridge area that we acquired from Great Western. While it's 100 percent permitted, we want to note that our teams are working on various inventory expanding opportunities that was not included in the original transaction.

Speaker 3: Our least permitted acreage is in the black oil window in the north, but it's also located in very rural areas with less permitting risks due to minimal building units and structures to plant our surface locations around. We look forward to pursuing these permits in the future. The table on this slide highlights our perwell reserves for our 2-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 the development of our Grinnell Cap assets in 2024, keep in mind that the cap is located in the light oil and retrograde gas windows.

Speaker 3: 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 a 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. All dollies, listen up, andherence points out the

Speaker 5: 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 size as our teams continued to set records, investments related to the cap, and continued to expand.

Speaker 5: 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-end GNA expense total $1.60 per BOE. In the Wattenberg field, we invested approximately $200 or $320 million to run three drilling rags and two completion crews during the quarter. We split 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 1.5 workover rigs to manage our base operations in the field. Production in the Delaware basin averaged $219,000 BOE.

Speaker 5: 28,000 BOE per day, of which approximately 39% was oil. LOE in the basin came in at $7.03 per BOE and is reflective of the continued workover activity during the quarter. Moving to slide 12, I wanna take a little more time to dive into the Wattenberg Field Operations and build upon some of the details Lance provided earlier in the call. Our Wattenberg assets has industry-leading economics and years of Tier 1 inventory development mapped out. Before highlighting the longer-term outlook in the basin, I wanna provide an update on our 36 well gusts and 28 well cordumpads that are beginning to be turned on in line in our new acquired range area.

Speaker 5: Completion's 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. Information from these 60 plus wells that are in process of coming online 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.

Speaker 5: 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.

Speaker 5: 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 workover rigs as part of our normal operation to support our base production. Additionally, we continued our batch drilling operations utilizing one full-time drilling rig. The batch drilling process is where we drill the surface of each of the wells on the pad before moving on to the intermediate sections and finally drilling each of the lateral sections. We anticipate this process may result in reducing drilling days and ultimately costs.

Speaker 5: The completion activity in the field resumed as planned in January of this year, and the 2023 program 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.

Speaker 5: in our core inventory count. With that, I will turn the call over to Scott Meyers. 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-hedged realized price of approximately $50 per BOE, while operating expenses came in at approximately $8 per BOE. Our G&A came in as expected at approximately $1.60 per BOE, exclusive of the approximate 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.

Speaker 5: 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-based dividend target. Our returns framework that we laid out earlier in 2022 is underpinned by the robust inventory of economic law-blown live 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 added action. 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.

Speaker 5: 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 of the primary tool in our shareholder's return program and anticipate being able to buy back another 7 to 10 percent of our shares in 2023.

Speaker 5: 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 have already committed $118 million of returns during the first quarter. Finally, on slide 19, I want to provide more detailed guidance for 23 in the first half of the year.

Speaker 5: 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.

Speaker 5: 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-op infrastructure for a recently approved cap, land, and ESG related projects. In the Delaware, the company plans to invest and invest approximately 20% of the total capital investments by running a one-rig program and a part time completion crew.

Speaker 5: 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

Speaker 9: of the activity level in the first quarter that includes more than 60 Wattenburg 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 PDCs continued and long-term success in building value for our shareholders. We exited the year with approximately 1.1 billion equivalent to your one-proof reserves, a rock solid balance sheet, 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 1-1 on your telephone and wait for your name to be announced.

Speaker 9: to withdraw your question, please press star 1-1 again, one moment while we compiled 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, can you maybe just give us a little bit more color on the cash tax guidance? I think it's a little bit below, but we had at least been anticipating for you guys for this year. Is there anything specific that you can point to? And maybe has to rethink about cash taxes on a go forward basis. Yeah, thank you for the question. Yes, a couple of things lined up for us for 2023. One of them was that we had better than expected GW for a great Western acquisition cost allocations, which increased our duct profitability in 2020.

Speaker 3: 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 whether or not we should always assume PDC prefers a two-basin strategy? Thanks guys. Yeah, thanks Gabe, I appreciate that. Good question there. We really set back strategically and really think that having.

Speaker 3: that we're going to be testing this year. You know, 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 comes together.

Speaker 3: then we're probably adding another couple, three years to our inventory with a one-rig pace and all. So that by itself is sustaining for us. We like how that fits and presents itself. And then, of course, on the inventory building side from the acquisition standpoint, we have a very 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...

Speaker 6: One moment for our next question. And our next question comes from Arun Jayaram of JP Morgan. Your line is open. Yeah, good morning. I wanted to see if you could provide a little bit more insights on your 2023 program at the Wattenberg field. I think you guys have highlighted just over 200 TILs this year. Can you give us a sense of between the four areas that you highlighted on slide eight of the general mix of activity?

Speaker 9: between the black oil in the north-south, light oil in the retrograde condensate parts of the field? I could just jump in here. I jumped to slide nine. The reason why I'm jumping to nine, you can see that almost all of our wells that will be turning on in 23 are ducks as they enter 23. When you look at it, you can see that we're hitting all of the areas. I'd say probably 90% of our turn-in lines are going to be from those ducks.

Speaker 6: the company, do you expect to be completing more footage over this kind of five year window? And is a higher mix of called wells in the Gwinnell, the 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 we're really trying to point...

Speaker 9: 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.

Speaker 9: 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 as production while gas and NGLs are probably growing a little bit per well, which still leads to great economics. Right, and the read-through from this slide is that in 2024, that your oil production should stay relatively flat on the year of your basis, but maybe your BOEs is down a touch? No, I don't think that's the goal of room. This is bottom. I think obviously the 2024 plan still has a lot of polish. But

Speaker 7: I think overall production growth, modest soil growth are still the goals for us. Okay, and there's a lot of levers we can pull to achieve that. That's correct. No, great. Thanks a lot gentlemen. One moment for our next question. And our next question comes from Yumeng Chaudhry 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-all 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.

Speaker 5: 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. 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.

Speaker 5: 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 ten-year window and we're strategically planning that with infrastructure and all the other things associated with that CAPRAT at this point. Great, that's what you have for arm.

Speaker 9: Share repurchase is gonna 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 years, trying to get that debt down.

Speaker 9: 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 Down 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 a lot of your shares and then the cap gets approved and then there's kind of a rerating 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 victory flag on buybacks and switch to more cash payment or do you really need to see your multiple, you know, go higher from here? Yeah, we still think, we still look at the multiples, look at the markets and we don't see a discernible trend between...

Speaker 9: which one and through talk to our investors, everyone's very supportive of them to share buy back. So right now, I think we're gonna stay on that track. I mean, we still think our shares are undervalued. We still think there's room for growth. Yes, it was a big step for us with the cap approval. But now I think people that haven't been looking at domains 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 gonna stay with the share buy back approach and look to have an aggressive plan in 2023. That's great. 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 process 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 a concern.

Speaker 3: to progress over time, we're essentially sorting the 20 to 24 well per section spacing per DSU. We've got a lot of data in history that really shows that that's the right spacing to bring the value out of the DSU itself and deliver exceptionally strong economics. That's what you're seeing in the economics table there as well. There will be a few areas we're going to test something even tighter than that in a few areas just to see what the potential upside could look like. Keep in mind too that some of those tighter spacings have us targeting some of the Niobrara A as well. That was one of the things that SRC had done before PDC and SRC combined together. That's kind of the general spacing that we have there. 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, do 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 SRC where they planned a lot of As and Codels. I think it's a subject of the gun barrel with the Niobrara, the Codel, and the As being the peak of that procedure. Be nice and simple.

Speaker 3: over time, we're essentially sorting the 20 to 24 well per section spacing per DSU. We've got a lot of data in 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 PDC and SRC combined together. So that's kind of the general spacing that we have there. 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, do 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 SRC where they planned a lot of A's and Codels. So I think it's a subject of the gun barrel with the Niobrara's, the Codel, and the A's being representative in that package.

Speaker 5: Okay, well, that sounds good. If Lynn started it off, I'm sure it's good. Maybe just to follow up, 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? Well, 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, okay? So without having all the calendar and the drill schedule in front of me, just expect that to be more information that we will obviously communicate to the market. Yeah, and I think there might be some comparisons on those spacings. We're going to start really drilling the summit area up with the Chalk, the Whitney, the Bypass, Denali. So there could be some good comparisons to look at, as we always evaluate our spacing and look backs, and our production will 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.

Speaker 5: I really appreciate the details that you all provided on the economics of the various space 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 from the more gas-directed drilling towards oilier 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.

Speaker 4: The thing to just remind you, going to one of the slides that Dave presented, the oil content, or lateral foot on those reserves is pretty consistent, and the gas is all incremental revenue. The economics, even in poor gas prices, are incredibly strong. They probably still improve on the gaseous wells. I can assure you that the value we're delivering to the shareholders with the drilling programs is phenomenal. I don't think we have a lot of flexibility in the drilling program, the way it's laid out. Dave, did I...? Yeah, that's exactly right. When we plan this out, it falls in place with our permits in hand.

Speaker 5: 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 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 preplanned.

And that's barely significant planning also. 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. It's just another component of the complexities in the Wadenberg and 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 of the year yet. So just kind of wondering if we might be able to get some more incremental colors 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 with thinking about exiting the year and heading into 2024. Yeah, I mean, I mean, it are from what I've messaged before we really haven't changed anything. Just just think of it this way in the in the second quarter as I said on the call today, our capital to midpoints down about 75 million. And that's because you're Delaware completion crew and the second Wadenberg completion crew are going down. The third quarter we really only have one completion crew running. That's the Wadenberg completion crew. And that comes back in the four.

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 there? You know, I would say just in general terms, I would say that the

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, 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. We'll see how that goes. There's another... You're saying 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 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. 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. At the last minute before we went in for our application, we changed some of those packages to three miles based on the lane results that we were getting. We continued to look to drill further and further. The economics get better and better because you don't have your steel costs. The technology with rotary steerables right now is just doing phenomenally well for us. Nick, to put it in 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 for my lateral. Appreciate it!

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.

As a follow-up here, looking at this mix of the subsurface that you all broke out, I'm kind of curious where things stand right now with gas processing and GL capacity to handle maybe a slight uptick in gas waiting here in the near term. I just 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 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. 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, 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 NGLs also. So from the field all the way down to the market, we feel we're in a pretty good spot where that sits. More to go, but we're staying right in lockstep with them and sharing our plans so that they can be prepared.

All right, that's great. Well, thanks everyone for the time. I really appreciate it. One moment for our next question. Our next question comes from John Abbott at Bank of America. Your line is open. Hey, good morning and thank you for taking our questions. Just a few quick ones from me. 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 years. 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 2024 and 2025. Appreciate that. Then for our follow-up question, it's not your plan as you do pursue growth, but where do you see long-term maintenance capex in the DJ? Long-term maintenance capex is...

billion one one somewhere around there. I mean we're growing three to five percent now as a company. So I mean we're not that far away, but my best estimate is as you're going through this will be somewhere between that billion to one one was probably my guess. Yeah and I'm probably in the same range just thinking through this. We also have some non-production related capital built into our 1.4. You gotta peel that out. Then you have to say what does it take to keep it flat basically for a few years. And we're probably in that 1.1 range maybe a little higher. Appreciate. Thank you for the color. And our next question comes from Noel Parks of True 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 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

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...

to monitor 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.

Q4 2022 PDC Energy Inc Earnings Call

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