Ladies and gentlemen, thank you for standing by, and welcome to the Callon Petroleum third quarter 2022 earnings 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 on today's call, you can press star one on your telephone keypad. To remove yourself from the queue, you can press star one again. Please be advised that today's conference is being recorded. I would now like to hand the conference over to your speaker, Kevin Smith, Director of Investor Relations. Please go ahead, sir. Thank you, Lisa. Good morning, and thank you for taking the time to join our conference call. With me on today's call, Joe Gatto, President and Chief Executive Officer, Dr. Jeffrey Balmer, SVP and Chief Operating Officer, Kevin Haggard, SVP and Chief Financial Officer. During our prepared remarks, we may reference the earnings results presentation and our third quarter earnings press release, both of which are available on our website. I encourage everyone to download both documents if you have not done so already. You can find the slides on our Events and Presentations page and the press release under the News headings, both of which are located within the Investor section of our website at www.callon.com. Before we begin, I'd like to remind everyone to review our cautionary statements, disclaimers, and important disclosures included on Slide 2 of the presentation. We will make some forward-looking statements during today's call that refer to estimates and plans. Actual results could differ materially due to the factors noted on that slide and in our periodic SEC filings. We will also refer to some non-GAAP financial measures today, which we believe help to facilitate comparisons across periods and with our peers. For any non-GAAP measures we reference, we provide a reconciliation to the nearest corresponding GAAP measure. You may find these reconciliations in the appendix to the earnings presentation slides and in our earnings press release, both of which are available on our website. On our prepared remarks, we'll open the call for Q&A. With that, I'd like to turn the call over to Joe Gatto. Joe? Thank you, Kevin, and good morning to everyone on the call. As a reminder, please refer to the earnings presentation on our website as background for our commentary. I will be highlighting a few pages in particular as I walk through introductory remarks over the next few minutes. We posted strong results this quarter that were underpinned by sequential production growth of 7% on a BOE basis and 8% on an oil-only basis, exceeding both our guidance and consensus estimates. These gains were driven by well performance that was above expectations and consistent execution in the field, particularly on the completions front, with reduced cycle times in the Permian and Eagle Ford. At a bigger picture level, our commitment to a life of field development philosophy of our multi-zone resource base, paired with continuous improvements in drilling and completion designs, has resulted in year-over-year improvements in Callon's well performance at a time when concerns around inventory degradation are increasingly becoming a focal point of the industry. Pages 8 and 9 of the third quarter earnings presentation provide a reminder of the benefits of our philosophy. Specifically, we've provided illustrative gun barrel diagrams that compare the co-development approach that we've employed over many years to an alternative strategy of near-term high grading that comes with negative implications for capital efficiency over time. We highlighted an approximate 20% improvement in Delaware productivity versus 2021 during our second quarter earnings call, which has continued to increase into this quarter and have delivered a similar level of improvement with this year's Midland Basin activity, as seen on pages 6 and 7 of the presentation. Additionally, we realized that reduction in our per unit lease operating expense, which contributed to another increase in our Adjusted EBITDA for BOE and an 18% sequential increase in free cash flow generation despite lower benchmark oil and NGL pricing relative to the second quarter. Operational capital was within our guidance range, and this capital cost control also benefited our free cash flow profile. Turning to operating costs, we initiated an ESP conversion program in the Delaware Basin earlier this year. After accelerating this activity in the second quarter, we realized a sequential reduction in workover expense in the third quarter as our conversion program reverted to normalized levels. Offsetting this reduction in our lease operating expense was an increase in fuel and power costs this quarter that were driven by higher prices and surcharges related to grid congestion in the summer months. However, we are starting to see relief on these line items as we head into year-end. Before moving to our outlook for the remainder of the year, I want to highlight that we published Callon's third annual sustainability report in September, which detailed another year of substantial progress across several important initiatives, including a 49% reduction in flaring rates and 11% reduction in GHG emissions intensity. With these achievements, we remain on track to achieve our goal of a 50% reduction in emissions intensity by 2024. If you have a chance, I highly recommend you read the report which can be found on our website. Looking ahead to the fourth quarter, we expect to maintain the positive momentum from the third quarter and deliver our best quarter of free cash flow for the year, with production in the range of 105,000-108,000 BOE per day. We recently added a sixth rig in early October to ensure the security of high-quality drilling services in a tight market and to support our operational plans in early 2023. These plans now include multiple large-scale Permian projects, each with over 10 wells targeting multiple zones in keeping with our co-development model. With the early addition of a sixth drilling rig, we created more operational flexibility to execute these projects without significant modifications to our overall 2023 D&C plans and associated timing of production. Importantly, we will be completing these projects using two simultaneous crews running consistently in this mode of development through the first quarter, adding the benefits of improved cycle times and resulting capital efficiency to the economies of scale of larger projects. The sixth rig is scheduled to begin operations this quarter, and we also plan to run one completion crew for the remainder of the year before adding back a second dedicated crew for simultaneous operations at the beginning of 2023. The number of gross wells placed on production in the fourth quarter is expected to be between 20 and 24, and our operational capital spending to be in a range of $180 million-$195 million on an accrual basis. I will now turn the call over to Jeff to discuss operations. Thank you, and good morning, everyone. I'm very pleased with this quarter's results as we exceeded our production forecasts, averaging 107,000 BOE per day and also reduced our per unit operating costs. I'd like to point out that the work we did early in the year laid the foundation for the growth we are experiencing now. As Joe discussed, our development program is focused on disciplined co-development of large projects, which is the most capital efficient way to develop our multi-zone asset base with more consistent well productivity over time. For the quarter, we placed online 43 new wells, a 30% increase from the second quarter. We continue to see the benefits of our active ESP optimization and conversion programs in the Delaware Basin, realizing strong initial production responses and more stable production profiles. Across all of our operating areas, we are always looking for ways to reduce well costs and improve overall production performance. Earlier this year, we made some modifications to our completions design in the Eagle Ford, focusing on pump schedule and fluid properties, which enabled us to place the same amount of proppant per stage with less overall fluid. Besides reducing the cost of the well, the reduction in fluid resulted in faster first oil production post-frac, and also less impact on offsetting parent wells, enabling us to return them to pre-frac production levels much faster. Another cost savings and operational efficiency item that we have successfully implemented is the use of coiled tubing to drill out plugs post-frac in the Midland Basin. This is a technique, of course, that we've been utilizing in the Delaware and Eagle Ford, and through the use of a nitrified mud system and changes in frac plug design, we were able to implement it recently in Midland. Using coil to drill out frac plugs not only saves us money, but also enables us to get wells on production much more quickly, improving cycle time to first oil. I'd like to provide you with an update in each of our operating areas. Let's start with the Midland Basin. Our Midland Basin asset continues to outperform, particularly in Howard County. We've developed this acreage in a thoughtful, committed manner that maximizes recovery and overall capital efficiency. This multi-zone integrated subsurface correlation protects both our future inventory and existing wells from unnecessary degradation. A great example of our co-development model is the Ponderosa project, a 11-well venture with 4 target zones, including the Middle Spraberry, Lower Spraberry, Wolfcamp A, and Wolfcamp B formations. This project is performing above expectations with all zones producing above the type curves. In addition, we placed 8 Colonial and Windham unit wells on production in central Howard County that offset legacy wells that have been online for several years. These 8 wells achieved strong production results with a peak average 30-day rate of over 150 BOE per day, per 1,000 foot of lateral with an oil cut of 85%. This is very much in line with the initial less bounded older wells. Because Callon has the advantage of being a multi-basin company, we don't have to overcapitalize any individual asset, so we can rotate our development strategies and plan for the future while executing strong current year performance. During the majority of the quarter, we had two rigs running in the basin and drilled 14 gross wells. We dropped down to one rig at the end of the quarter on our Midland acreage and plan to maintain that level of activity through the remainder of the year. Shifting to the Delaware. During the quarter, we completed 12 gross wells [and brought online 10] in Reeves County. We've been focused on our eastern and southern part positions in the Delaware for most of the year and are now turning activity to the Delaware West. I'll highlight one project in particular, our 4-well Fox project that has been online since July. These wells targeted both the Wolfcamp A and B with an average lateral length of 10,750 feet and have a peak average 30-day rate of approximately 1,700 BOE per day with an oil cut of 51%. Similar to other projects earlier this year, the Fox program employed higher proppant intensity and is benefiting our well productivity and economics. Moving to the Eagle Ford. Production from this area also continues to be a key part of our robust asset mix, and we were able to bring on wells earlier than expected, given some of the operational improvements that I previously discussed. During the quarter, we brought online 11 new wells, which completed our 2022 Eagle Ford program. One of the wells that was brought online in the third quarter was an initial test of the Austin Chalk potential on our leasehold. We are still early in the flowback of this well, so it's a bit early to discuss production results. I can say the results of the subsurface evaluation from the logs we ran are encouraging and consistent with our pre-drill characterization of the target formation. In aggregate, we finished the quarter with five rigs and one completion crew, which is a good transition to provide an update on where we stand with regard to securing services for next year's capital plan. We currently have one dedicated completions crew contracted under a multi-year agreement and have recently entered into a contract for a second crew that will combine to cover our activity for 2023. On the drilling side, our rig requirements are contracted under laddered maturities, which ensure high quality services while also maintaining a high degree of flexibility. We've really enjoyed outstanding relationships with our primary partners and anticipate more of the same in 2023. With my final comments, I'd like once again to acknowledge Callon's field operations teams as they've continued to perform extremely well across the board. This year has not been without its challenges. We're integrating a new asset in the Delaware South. We've ramped up completions activity, and we've done all of this in a very tight oil field services environment. I'm really proud of the results our team has been able to deliver and remain extremely excited about what we can accomplish in the quarters and years ahead. With that, I'll now turn it over to Kevin to handle the financials. Thanks, Jeff. During the third quarter, we posted strong financial results, delivered on further deleveraging, and increased our debt maturity runway, which by the way, is now the longest weighted average bond maturity profile in this mid-cap space. Let's go through some key financial details. First, we experienced a quarter-over-quarter reduction in oil and NGL prices, resulting in a 12% decrease in wellhead revenue to just over $73 per BOE. However, on a post-hedge realized basis, our revenue per barrel of oil equivalent was largely unchanged from the second quarter as the oil hedging losses declined sequentially. As a reminder, the back half of 2022 has lower amounts of production hedged as compared to the first half of this year. After factoring and hedging it and the reduction in per unit LOE and G&A operating costs, Callon reported its ninth consecutive quarterly increase in Adjusted EBITDA per BOE to over $46. Our top-tier operating margins helped us realize Adjusted EBITDA of $459 million in the third quarter, a 10% sequential increase over the second quarter. During the third quarter, Callon generated adjusted free cash flow of approximately $150 million, a number which we expect to increase again in the fourth quarter. We used this quarter's free cash flow to reduce the borrowings under our revolving credit facility by approximately $140 million. At quarter end, we had $636 million drawn on our facility, leaving us approximately $850 million of availability based on our recently amended credit facility. In total, during the first nine months of this year, we've reduced our debt balances by approximately $330 million. In addition to using free cash flow to retire debt, we remain opportunistic in taking steps to further strengthen our financial standing. We recently redid our revolving credit facility, extending the maturity date of that to October 2027. The new facility has a borrowing base of $2 billion and an elected commitment of $1.5 billion. Excluding the $187 million unsecured senior notes due in 2025, which we expect to retire with free cash flow in the coming year, we will have no debt maturities until July 2026. Turning to our hedge profile, we have a good base layer of hedges for 2023 at this point and are in the mid-20% area in terms of hedged oil volumes. We remain constructive on crude oil prices and will continue to layer into a moderate hedge position on price strength to take advantage of optimization opportunities on sell-offs and heightened market volatility. Next, I wanna discuss the upcoming accounting change from full cost to successful efforts. As we discussed last quarter, starting in 2023, we plan to report our financials using the successful efforts method of accounting. We have prepared some slides discussing the reasoning behind the change and highlighting the line items in the financial statements that will be impacted by the conversion. The main items on the income statement impacted by the conversion are interest, G&A, and exploration expense. I do wanna keep reminding everyone there is no impact to cash flow from this accounting change. I encourage you to look at the slides in our quarterly earnings presentation for more details about the differences between the two method, as well as generalized financial impacts to Callon. Expect more explanation in the coming months when we offer formal 2023 guidance. Finally, I would like to also say a few words about our outlook on cash taxes. This item has become pretty topical in our industry recently and reflects positively on how profitable the E&P industry is in the current environment. At year-end 2021, Callon had over $1 billion of net operating losses that helped to offset our income and reduce our tax burden. Taking into account our NOL position and making some CapEx assumptions, we expect to pay minimal cash taxes in 2022 and 2023 in the range of $10 million-$20 million per year. However, depending on oil and natural gas prices, as well as a host of other operating assumptions, we expect that number will increase in 2024 as our net operating loss balance decreases. With that, I'm gonna turn things back over to Joe before we move to Q&A. Great. Thanks, Kevin. Before moving to questions, I'll leave you with a few key takeaways. Our focus on co-development of top-tier zones has created a visible path for sustained inventory quality for future drilling as we've steered away from just drilling our best wells at the expense of degrading offsetting locations in adjacent zones. This has allowed us to continue to realize increases in well productivity in the Delaware and Midland basins at a time when other operators are seeing declining productivity levels. With the scaled model of development comes repeatable drilling and completion activity, the benefits of which we saw this quarter, with the 2022 operational plan being executed as laid out at the beginning of the year. We've been actively securing the right services and partners for 2023, which will provide the foundation for consistent execution in the quarters to come. Additionally, we remain focused on continuous improvement and are still finding ways to reduce costs and increase well efficiency as we modify our drilling and completion methods and apply emerging technologies. Finally, our financial position is solid, and we will continue to improve at a fast pace into year-end. Financial strength will remain a key priority for the longer term, even as we look to implement return of capital frameworks in the future. With that, Lisa, if we can open up for Q&A, that'd be great. Thank you. If you would like to ask a question on the phone lines today, please press star one on your telephone keypad. Again, to remove yourself from the queue, that is, press star one again. We will take our first question from Neal Dingmann with Truist Securities. Morning, Joe and team. Thanks for the time. Joe, my first question, just maybe get right to it, is on your large-scale development. Specifically, it's been interesting, there's been a lot of attention this earnings season on companies talking about, I don't know, multi-stack, full-scale development. To me, this seems largely what y'all have been doing with your life of field development now for quarters. I'm just wondering, could you maybe provide some details on how you all view your program may be the same or different than some of these, you know, programs that others now just are recently seem to be changing? Sure, Neal. You know, we have been doing this quite consistently over the last few years. You know, it's interesting it's coming to light now, and we've stuck to our knitting on this, and I think we're starting to see the benefits of it. You know, it's a little bit more of a medium, long-term type of strategy versus short term, but the medium and long term is here now. This is where we're gonna see differentiation. Yeah, in the slides I alluded to, I think it was pages 8 and 9. We provided some examples of how our co-development strategy lines up to an alternative strategy, if you're just high grading all of your best zones and what that means for potential degradation, down the road. It's good to see that this is coming to light. But you know, for us, this has been a consistent message that we've had over the last few years because we knew that if you made near-term drilling decisions in terms of high grading, we'll have longer term value impacts. That's what we wanted to preserve more consistent capital efficiency over time versus hitting a wall on that over the next few years. No, clearly seen. Then just to follow up, trying to get a sense on the latest rig, the sixth rig that'll be coming. I'm just wondering, on that, will the duration of that sixth rig be sort of price dependent next year, or do you already have firm plans on, you know, what that duration of that rig might be through next year? Yeah, we've been putting together the 2023 plans pretty proactively. We'll provide some more detail here in the coming months, but this will very much be a part of the plan for most of 2023. Importantly, with all of the contracting we've gotten ahead of, especially on the drilling rig side, we have laddered maturities, so we do have some flexibility if we wanna move away from the base plan. We wanted to make sure that we underpinned certainty of services throughout the year and then add on some flexibility if things needed to pivot. Great to hear. Thanks for the details, Joe. Sure. Thanks, Neal. We'll take our next question from Derrick Whitfield with Stifel. Thanks. Good morning, all, and congrats on your strong ops. Thanks, Derrick. Perhaps for you, Joe, as you guys are rapidly approaching your deleveraging goals, could you help frame your thoughts on when you'd be in a position to announce return of capital and your views on preferences on the appropriate split between dividend and share repurchases? Sure. You know what? I'll let Kevin start off here since he's been out in front, walking us through the analysis with the board and the management team. I'll let him start, and I can pick up, but I'm sure he'll cover this well. Yeah, Derrick, I think we've been consistent on each call for the last couple of quarters. We wanna hit those targets before we announce. The $2 billion of debt and the 1x leverage target, we hit those and we'll be ready to go. We still have some runway between there and here. In terms of preference, we're certainly watching our peers out there and seeing what folks are doing. We've given a number of recommendations to our board. I think we're still waiting to clarify what that mix of shareholder returns will look like. I think, Derrick, just to follow up on that, one thing that, you know, we have to fill in some details, but philosophically, you know, as a mid-cap company, we think one of the benefits we have is being able to be nimble, being able to allocate capital in different ways. Any framework that we come out with, I think the overarching principle will be not to limit our flexibility to allocate capital, you know, obviously continue to pay down debt, to have opportunities for smaller acquisitions that can live on the balance sheet, type of bolt-ons, returns of capital, et cetera. You know, we wanna avoid taking away that flexibility with anything that's overly formulaic. Terrific. As my follow-up, I wanted to talk to your life of field concepts on page 9. I think there's a general misunderstanding around Pioneer's message this quarter. Maybe for the benefit of the investor community, could you broadly speak to the intervals included in life of field development plans in Howard and Reeves? I'm asking for broad development. As I understand, past operator activity could skew it. Absolutely. This is Jeff Balmer. We can start in the Howard County. The page 9 is a really good general representation of what would benefit companies to have done similar to what Callon has done on the left-hand side, and then the potential. Negative ramifications of cherry-picking and only drilling up your best stuff on the right-hand side. What Callon has done, similar, for instance, to the Ponderosa pad that I'd mentioned earlier, is remain committed to a large scale, vertical and horizontal integrated system. For instance, the most recent pad drill, the Middle Spraberry, which is normally a pretty well segregated interval that's multiple hundreds of feet on top of the rest of the stack. The Lower Spraberry, which has been an extremely strong performer in the Midland Basin, and then the Wolfcamp A and the Wolfcamp B. If you think about that 11-well project, for instance, you're really advantaged by going out and you have your high productivity bread-and-butter zones, but they're complemented by the operational efficiencies of drilling and completing and providing water and getting water, all the time when you're out there once. Then you also benefit from the offset wells surrounding it. The existing parent wells are fairly spread out, so this is a half section that we're developing. You have limited amount of shut-in time for those parent wells. They get returned to production relatively quickly, and that's the only thing that you have to do. You're not coming out 6 months later or 2 years later and drilling another 3 wells or drilling vertically above or below some of the existing production, which creates significant degradation to the wells that you're putting in into the system. It's fairly similar in Delaware. It's very similar, but it's slightly different on what the stack looks like. As we alluded to, there is an opportunity for organic delineation in some of the shallower and deeper zones. While the Wolfcamp A would be kind of your primary stack, which is shown in the highest return segments in the green, we're also drilling Wolfcamp B, and we've got a Wolfcamp C deeper test planned. What the idea behind it is to have a very robust overall, and whether we call it, you know, profit-to-investment ratio, rate of return, you name it's much better to come out and drill that stack both laterally and vertically, as opposed to cherry-picking. When you come back out later on, and it doesn't matter if it's, again, a year or two years or three years, you will have significant degradation of all the wells within that system, due to simply depletion effects. Virtually all those wells are gonna interfere with each other one way or another, and the best way to maximize capital efficiency is to do the majority of it all at once if you have that opportunity. Joe answered this before, but I'll reiterate this. Callon has been doing this for a long time. We've been very thoughtful and committed to our development program, even in 2020 and 2021, where there were some cyclical commodity prices. I think you'll see that Callon continues to reap the benefits of this very thoughtful development program. Jeff, if I could just squeeze in one additional question. I wanted to focus on Slide 7. Really first and foremost, I wanna compliment you guys on your operations in Howard in light of the headwinds that your peers are experiencing. Referencing that Slide 7, could you speak to some of the drivers of your year-over-year improvement in Midland well performance? Is it D&C design or location? Because the mix, I mean, you guys have been incorporating life of field now for some time, but there's definitely some outperformance there that you're benefiting from. Yeah. Thanks for pointing that out. We're very proud of that position. First and foremost, it's excellent rock. That helps quite a bit when you're in an acreage position that you have the opportunity to experiment and optimize something that's already good in its natural state. The performance of these wells continues to be an outcome of this thoughtful and committed development program. When we come in and we can drill multiple pads on the same development program, we'll have a rig that'll come out and drill, you know, 4 wells and another rig next door to it. Its sister rig will put in 4 wells, and then you can mow the lawn from a completion standpoint. You're able to look over time at opportunities for testing changes in completion design, frac plugs, drill outs, what we should do from some of the neighboring wells on how we should shut those in, and the time it takes to return those wells onto production. What are the geomechanics of the reservoir system on how the rock breaks and how it transfers fluids across the system. Because we have a multi-basin asset, we're able to rotate our capital intensity around so that we're not committed to doing only one asset from a development perspective. We can attempt different items with technology applied to it, and then we reap the benefits of watching them over a series of months, or in this case, several years, to determine not just what the short-term effects are on productivity, but the medium and longer-term effects. When we come back into these areas and drill, for instance, the Ponderosa and the Colonial Windham units, you know, those are large-scale developments on half sections, relatively greenfield. You'll see this, you know, this just very robust, educated approach to the development of those areas. Great update, guys. Thanks for your time. Thanks, Derrick. As a reminder, everyone, that is star one to ask a question. We'll take our next question from Paul Diamond with Citi. Good morning, all. Thank you for taking the time. I wanna start my first question, actually a bit of an extension of the last one. Slides 6 and 7, you guys are obviously showing some production gains. In you guys view, how much more of their meat on the bone or how much more meat on the bone is there? And do you guys see that, you know, kind of cadence there slowing? Or I guess, how much more do you think you guys can wring out of those developments? The Delaware is less mature than the Midland Basin, so my thoughts on the opportunity is probably a little bit higher in the Delaware Basin simply because it's a little more of an unknown and less mature from a development perspective. In addition, what we're looking at is some organic delineation, so we'll be testing some slightly different zones, and we'll get some information on how those interact with each other. One advantage that Callon has is through how Callon was built over time, we've had three independent datasets from different companies that have combined to result in a very advantaged subsurface evaluation. Callon originally, prior to the Carrizo acquisition, was more focused on the lateral interference and effects on wells drilled next to each other and the parent-child relationships over time and the lateral distances. Carrizo had done some outstanding work on the vertical integration of zones, on how they would interact with each other, the timing of it. Were some of the zones segregated so that they weren't necessarily needed to be developed over time at the same time, or could you wait? Then the Primexx acquisition in October of 2021 had a tremendous subsurface dataset on seismic evaluation, artificial intelligence, machine learning. Now Callon is the beneficiary in aggregate of these three well-developed, interpreted and integrated datasets. That there's still an opportunity, I think, in the Delaware to continue to grow and evaluate, what the optimal development program should be. What you can see is the company, you know, flexing its muscles on some of the outcomes that are pretty black and white. Not to say there's not opportunity in the Midland Basin, but it is a slightly more mature basin, for us. We'll still continue to obviously evaluate it and optimize it, but I would say the Delaware has slightly more upside. Understood. Thanks. Just as a quick follow-up, as you plan out your 2023 development cadence and cost structure, how are you guys seeing inflation impact that? Is the trend continuing unabated, or have you guys seen any particular, you know, easing points or pressure points kind of come up in those conversations? Yeah. I'll start at a high level, and Jeff could probably talk to some of the areas where we're seeing some of the particular tightness. I think overall, in terms of the major categories, we've seen a plateauing. Again, these are general industry observations. As I said, you know, we've been very active over the last couple months, getting ahead of 2023 and accessing the right crews and services, and products moving forward and getting as much price certainty as we can, so we're not exposed to the spot markets which have, you know, continued to tick up during the course of the year. You know, overall inflation, I think estimates we've heard out there from others are in that 10%-20% range is where things started the last couple months. I'd say that what we're hearing and seeing is probably moving up to the top half of that range. Again, we've stayed ahead of that. We don't wanna be riding the curve out there in terms of spot markets. Let's get contracted with the right crews and services and let's get real contracts in place with price certainty in terms so we're in a repeatable program of development, which not only adds cost certainty but also benefits of just repeated activity, doing the same thing over and over with the same people and equipment. You know, I'd say one area on the big ticket items is probably on the casing side of things that's harder to lock in pricing there. You wanna work with your providers to get your allocation and make sure they understand your plans well in advance. That's where you're benefited by showing them, "Here's our 2023 plan. We're ready to go on this. We need this casing or steel," and they'll make sure to get it. Just getting price certainty is difficult to get in this market. There's probably some other ancillary pieces of the business that you don't really contract for but do have impact on where cost estimates shake out. I don't know, Jeff, you wanna hit about some of the tighter pieces? Yeah. That hit really the majority of the pieces. The short summary is that the average cost of doing business in 2023 will be higher than the average cost of doing business in 2022. You know, labor continues to be an issue across the board. What you'll see is companies that are performing better tend to have been on their front foot as far as policies to keep good employees and keep them employed, working on locations, et cetera. You'll see some benefits of that. Other items that'll continue to see some potential pressure will be the chemicals, the availability of good workover crews, those kinds of items. We anticipate having a very solid... We are already in a position where all of our primary contracts are either being negotiated or are negotiated. We have a very high level of confidence in executing our 2023 program. Understood. Thanks for your time, gentlemen. Thanks. That does conclude today's question and answer session. I would like to turn the call back over to Joe Gatto for any additional or closing remarks. Thanks, Lisa. Thanks, everyone, for taking the time out, the third quarter earnings call. Always appreciate, the time and the questions, and we'll look forward to, catching up again in the new year. Thanks. That concludes today's presentation. Thank you for your participation, and you may now disconnect.