Good day, and thank you for standing by. Welcome to the PDC Energy First Quarter 2023 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 one one on your telephone. You will then hear an automated message advising that your hand is raised. To withdraw your question, please press star one one again. Please be advised that today's conference is being recorded. I would now like to hand the conference over to your speaker today, Aaron Vandeford. You may begin. Thank you. Good morning, everyone. On today's call, we have President and CEO, Bart Brookman, Executive Vice President and Chief Financial Officer, Scott Meyers, Executive Vice President, Lance Lauck, and Senior Vice President of Operations, Dave Lillo. Yesterday afternoon, we issued our press release and posted a presentation that accompanies our remarks today. We also filed our Form 10-Q. The press release and presentation are available on the investor relations page of our website at www.pdce.com. On today's call, we'll reference both forward-looking statements and non-U.S. GAAP financial measures. The appropriate disclosures and reconciliations, including discussions of risk factors that could cause the actual results to differ materially from the 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. Thank you, Aaron. Good morning, everyone. Let me begin with a big call-out to the PDC operating teams in Texas and Colorado and our EH&S group. Both basins are approaching five years with no lost time injuries to PDC employees, an exceptional accomplishment. Thank you for your sincere commitment to safety. The first quarter, a solid performance for the company. Production of 22 million barrels of oil equivalent or 244,000 BOE per day, in line with our expectations. Free cash flow for the quarter of $100 million on a capital spend of approximately $450 million. CapEx coming in better than our expectations as we are seeing per well cost improvements in both basins. Dave and Scott will provide more detail on this encouraging trend in a moment. Costs for the company remain in check. LOE for the quarter, $3.33 per BOE, and G&A of $1.89 per BOE. Both metrics beating our expectations. We exited the quarter with a 0.5 x leverage ratio and an extremely strong balance sheet. During the quarter, the company returned $170 million of capital to our shareholders with the retirement of 2.1 million shares of our stock and a $0.40 per share of fixed dividend. Again, great results, a solid quarter with solid execution. Now, an exciting update on our outlook for the second quarter and the balance of the year. April is experiencing record production for both basins, a result of exceptional midstream and individual well performance, along with an accelerated Q1 turn-in-line schedule, where 2/3 of the quarterly TILs occurred in March. We're pleased that the outlook for the second quarter production has been increased to a range of 265,000-277,000 BOE per day, and our 2023 annual production guidance is now anticipated to be near the upper end of our guidance range. Also, with the improved well costs I mentioned earlier, our 2023 capital spend is being amended downward to a range of $1.35 billion-$1.45 billion, resulting in anticipated 2023 free cash flow of $875 million, an increase of $50 million from prior guidance. These are encouraging improvements in our outlook for production, capital spend, free cash flow, and overall capital efficiency, laying the groundwork for a very strong second quarter and a successful 2023. For more details around the company's operations, I'll turn this call over to Dave Lillo. Thanks, Bart. Jumping on to slide five, I want to review some of the operational achievements for the quarter. As Bart pointed out, our first quarter was the most operationally intense quarter of the year, running four drilling rigs and three completion crews across the asset base. For the quarter, we invested approximately $415 million, below the midpoint of our guidance. This is a result of a slight push of capital from the first quarter into the second quarter, but more significantly, reflecting some of the pass-through cost savings primarily associated with steel, sand, and fuel costs we've begun to see in the field. Total production for the quarter came in at 22 million BOE or approximately 244,000 BOE per day. Oil production for the quarter was 6.9 million barrels or approximately 77,000 barrels per day. Oil production for the quarter was slightly below guidance expectation as a result of turn-in-lines in two large pads, the Gus and the Kortum, in the Black Oil South acreage in the DJ. Although the timing delays were a matter of days compared to our guidance forecast, they took a bit longer to hit peak production. Of our 61 turning lines for the quarter, 36 turning lines occurred in the month of March due to a larger pad development and results of lumpy quarter production. To give a window into this production ramp already well underway, our March production averaged 253,000 BOE per day, with oil production averaging 81,000 barrels per day. Our April production has been even stronger as we set PDC field records almost every day across both basins. Today in the Wattenberg, all the Gus and Kortum wells are online and meeting or slightly exceeding expectations. We have upwardly revised our second quarter production outlook to reflect this timing change, and Scott will cover this in more detail shortly. As we work through a busy quarter, our team maintained great focus in managing costs on our LOE side. For the quarter was $3.33 per BOE and an all-in G&A expense totaling $1.89 per BOE. In Wattenberg Field, we invested approximately $330 million to run three drilling rigs and two completion crews during the quarter. We spudded 64 wells and turned in line 55 wells. For the quarter production in the Wattenberg average 216,000 BOE per day, of which approximately 31% was oil. LOE for the basin came in at $2.83 per BOE, highlighting our low-cost nature of our operations. In Delaware, we invested approximately $85 million, running 1 completion crew and maintaining our 1 full-time drilling rig activity level focused on batch drilling. Production for the Delaware Basin averaged 28,000 BOE per day, of which approximately 36% was oil. LOE for the basin came in at $7.14 per BOE. It was reflective of our continued workover activity during the quarter. Moving to slide six. I wanna take a little time to dive into our Wattenberg field operations and highlight some of the innovations in technology that was driving value for us for the quarter. The team has done a great job at continuing to look at all parts of our operations and identifying opportunities for improvement. First, to give you an update on our 3-mile laterals as our 10-well Wayne pad has been online for more than 120 days now. Our team is seeing no degradation in production results per lateral foot to date as we move to 3 miles of completed lateral length. We highlighted in the chart at the bottom of the slide our per well NPV-10 by lateral length, you can see a very linear relationship moving from 1 mile to 3 miles at this point. Continued success in development with longer laterals provide ongoing opportunities for step change improvements and efficiencies, as well as opportunities to recover incremental resources. As we continue to test the bounds of increased lateral length, our results to date give us good confidence to continue to complete 3-mile laterals going forward. In 2023, we have our Brant pad made up of nine wells and our Spinney well pad, which both we are currently drilling 3-mile laterals. Additionally, we have plans to test a 6-well pad with 4-mile laterals later this year. Moving to the use of local sand in the DJ operations during the quarter. 25% of our frack activity utilized this local sand, and we have subsequently been working to move that percentage up based on availability and allocations. Not only does this move to local sand reduce total completions cost, there is a sustainability benefit from sourcing this in-basin and not having to ship it in. Lastly, on this slide, I wanna highlight our continued progress to electrify our operations. We have started using an e-fleet for our completions and moving from diesel to on-site electrical generation and grid power beginning this week. We have continued to utilize grid power for drilling and changed out one of our existing rigs for a brand-new e-drilling rig in March. We anticipate using 80% grid power for our drilling operations in 2023. This electrification is not only setting us up for successful operations in our CAP acreage planned at the beginning of next year. We also receive incremental cost benefits today from insulating ourselves from diesel costs and realizing environmental benefits on emissions and reduced noise levels. On slide seven, I wanna point out an update of our Wattenberg or our Delaware operations. As you can recall from prior calls, our team has been actively finding ways to economically extend inventory in the basin through acreage swaps and drill-to-earn opportunities. One of these drill-to-earn opportunities executed in 2022 resulted in a six-well Redhorn pad that we completed in March of this year. For the first month of production, the individual wells averaged 1,000 BOE per day of oil and 55 million cubic feet of gas. These are very strong, highly economic wells that we are excited to have in our inventory today. In other inventory expansion opportunities, we recently finished drilling two Third Bone Spring carbonate/shale tests in our northern central acreage and anticipate completions at the end of May. We continue to be encouraged by results from offset operators. Based on successful preliminary results, we believe the potential to drill three more additional wells in the second half of the year exist. If successful, this could add up to 20 additional wells or an additional drilling year to our inventory in the basin. Lastly, I want to highlight some of the three-mile lateral development we are doing in Delaware. In April, we placed on flowback our six well Lost Creek pads. Although we don't have many days of production, I can share that we are very encouraged by the early results which this helped along with the Redhorn to set new production targets in the basin. I look forward to updating the market with more details on our progress in the basin in upcoming quarters. With that, I will turn it over to Scott Meyers. Thank you, Dave. Starting on slide nine, our free cash flow profile is extremely robust. In a quarter where we operated three completion crews and four drilling rigs, as Dave has highlighted, we generated more than $100 million of free cash flow. This is quite strong considering the elevated capital of level and the current natural gas price environment. To dive into some parts of our free cash flow result, we received pre-hedged realized price of approximately $37 per BOE, while our lease operating expense came in at $3.33 per BOE, and our G&A came in as expected at $1.89 per BOE. Total production for the quarter was 244,000 BOE per day, while oil production came in at 77,000 barrels per day. For this second quarter, we've increased the midpoint of our production guidance and now expect total production to be in the range of 265,000-277,000 BOE per day and 87,000-92,000 barrels of oil per day. The increase is primarily the result of the turn-in-line activity at the end of the first quarter, as well as the early well results Dave just outlined. Capital investment for the second quarter are expected to be approximately $325 million-$400 million, unchanged from prior guidance, as the realized savings we are expecting are offset by a slight push of capital from the first quarter to the second quarter. We ramp production in the second quarter and the back half of the year, we continue to see cost savings flow through our operations, we now anticipate generating approximately $875 million of free cash flow for the year, up from $825 estimate last quarter. Moving to Slide 10, I'd like to highlight a few details on our shareholder return program. In the 1st quarter alone, we returned approximately $170 million through our share buyback and our $0.40 base dividend. During the quarter, we spent approximately $135 million to repurchase 2.1 million shares, or nearly 2.5% of the company. The shareholder return program is intended to be an annual program, and we feel comfortable being ahead of our 60%+ in the first quarter as we expect incremental free cash flow to be driven from lighter capital activity for the remainder of the year. With our increased free cash flow estimate of approximately $875 million, we are now expected to return inclusive of our base dividend more than $575 million to shareholders this year. The share buyback remains our preferred tool on executing on our committed return of 60%+ of our annual post base dividend free cash flow to shareholders. Finally, on slide 11, I wanna wrap up our prepared comments by highlighting our progress in the first quarter has set us up well to execute on our 2023 plans. We've reduced our anticipated full year 2023 capital investment range to $1.35 billion-$1.45 billion to reflect savings we've already locked in for the second half of the year. We have reaffirmed our total annual production guide of 255,000-265,000 BOE per day with an oil range of 82,000-86,000 barrels per day. Although it's early in the year, current production performance and midstream run times gives us comfort pointing folks to the higher part of that range. As we sit today, PDC continues to set weekly production records in both DJ and Delaware. As wells continue to come on in the second quarter, we are on track to further reduce debt in the back half of the year and are encouraged by our free cash flow profile in the quarters to come. I am proud that we have positioned PDC and its shareholders to thrive in nearly every part of the commodity cycle. Though we cannot predict the ever-changing macro environment, with our long-lived inventory of Tier 1 assets, PDC is ready for the continued volatility to come. I will now turn the call over to the operator. Certainly. As a reminder, to ask a question, please press star one one on your telephone. To withdraw your question, please press star one one again. Please stand by while we compile the Q&A roster. One moment for our first question. Our first question will come from Neal Dingmann of Truist. Your line is open. Hi, good morning, guys. Good morning. ...to start off the, maybe you could go in detail on the timing of the turn-in-line activities in 1Q. I think it impacted volumes a little bit. Just wanted to see if, you know, what happened there and if you caught up on all that activity and, if maybe if anything is gonna slip from 2023 to 2024 as a result. The, the second question is just, you know, you have a pretty good diverse inventory when it comes to product mix. Do you plan to change any activity based on the kind, you know, the current gas oil prices, or is that all kinda locked in due to permits? Well, please, Dave. I'll take the first one anyway. What was really pushed as far as capital spend and a little bit of our production was we had a Gus pad, 19 brand new wells, 9 old wells, and then we had a Kortum, 26 brand new wells and 10 wells that were old. We had a 28 well pad and a 36 well pad. Our team is getting very familiar with the area that we're working in, down in Adams County. We've been very good at implementing sim ops operations with two drill out rigs. At the same time, we have flow back. What happened in this particular situation is that we had about half of our Kortum wells on at the end of the quarter. We finished up the work, and now they're all online. Basically, it shouldn't change any of our yearly production volumes, but the second quarter will benefit from this since they were turned on, this month or last month. Right. Just to reiterate that, I mean, this is a matter of a couple days, and when you're turning this many wells on this quickly, a week delay in production ends up being a little material. The second quarter, as Dave said, it's benefited. As we spend the quarter, we can now point to the top end of the 23 guidance. There's nothing that's getting pushed to 24. Yeah. On your question around commodity mix and scheduling and, the rigs, I wouldn't expect any big changes in our plan. We have tremendous economics on the drilling projects. The plan, the completions, the drilling schedule, everything is really well laid out by our planning group, and I don't see us making any significant changes to that, particularly with the resilient nature of these drilling and completion projects. Is there any change maybe year-over-year in 2024 versus 2023? That's all I got. Thanks. Again, I would say the only thing is we and this is like 1% or 2% of your oil mix. When we get to the CAP acreage, which is our old Summit and Plains area, we do get a little more gassy. That's just strong returns from that area. Generally speaking, over the next, you know, 5 years- 10 years, the oil mix is still gonna be in that 30%-32% range. We feel very comfortable to do this year after year. That's perfect. Thanks, guys. Again, if you do have a question, please press star then one on your telephone. Again, star and one for any questions. I would now like to turn the call back over to Bart Brookman for closing remarks. Thank you, Latona. Probably the shortest Q&A session we've ever had, so maybe that's a good thing. Good communications on our part and a great quarter. Thank you for all those who did join. We really are excited about the outlook for second quarter and the balance of the year and heading into next year. Appreciate you joining. Thank you. Ladies and gentlemen, this concludes today's conference. Thank you for your participation. You may now disconnect.