Welcome to SM Energy's Fourth Quarter and Full Year 2022 Results Webcast. Before we get started on our prepared remarks, I remind you that our discussion today will include forward-looking statements. I direct you to slide two of the accompanying slide deck, page eight of the accompanying earnings release, and the Risk Factors section of our most recently filed 10-K, which describe risks associated with forward-looking statements that could cause actual results to differ. We will also discuss non-GAAP measures and metrics. Definitions and reconciliations of non-GAAP measures and metrics to the most directly comparable GAAP measures and discussion of forward-looking non-GAAP measures can be found in the back of the slide deck and earnings release. Today's prepared remarks will be given by our President and CEO, Herbert Vogel, and our CFO, Wade Pursell. I will now turn the call over to Herb. Thank you, Jennifer. Good afternoon, and thank you for your interest in SM Energy. I'm very pleased today to share our results and achievements for 2022, and to look ahead to our 2023 plan that delivers value creation. Turning to slide three. Starting with our 2022 results, we not only met our key strategic objectives, we exceeded them in most cases and enjoyed an outstanding and pivotal year. Here's how we did. Our first priority was to generate increased free cash flow. 2022 adjusted free cash flow of nearly $850 million was more than double 2021, equaled a 20% yield to year-end market cap, and was achieved at a 52% reinvestment rate. Our second priority was to reduce leverage and position the company for the inflection point, the point where our leverage target is met, and we initiate a significant capital return program to stockholders. This was achieved early with net debt to Adjusted EBITDAX below 1x in the second quarter and absolute net debt near $1 billion in the third quarter. We announced our return of capital program in September 2022, earlier than expected, and tested that it was sustainable in a $60 oil and $3 gas commodity price environment. Our third priority was to demonstrate measurable ESG stewardship. Here we had meaningful improvements in flaring and greenhouse gas intensity, both Scope one and Scope two, and also maintained our low methane intensity threshold. These are the metrics that we use to measure our progress against short to medium term emissions objectives. Our operations technology team initiated testing of multiple fugitive emission detection and prevention technologies, efforts that will continue into 2023. Benchmarking against peers, SM scored very favorably in the CDP framework. Before leaving 2022, let me give a big thanks to our employees who went all out in 2022 to deliver not only on our financial targets, but demonstrated continued innovation and dedication to improve well results and EHS performance. Turning now to slide four. As we look to 2023, we start the year with increased commodity price volatility and continued inflation, albeit at a slower pace. Our core strategy, premier operator of top-tier assets, positions SM very well in this environment. Our high-quality portfolio offers low break-even cost production, the optionality to allocate more capital to oil or natural gas development, and significant free cash flow upside exposure to increased pricing. At the same time, we have established a return of capital program to our stockholders that is sustainable through the cycle while offering significant upside through share buybacks. Given this foundation, our strategic objectives for 2023 are to, first, deliver an increased return of capital to our stockholders as we initiate our first full year of the $0.60 per share annual dividend plus share repurchases, while at the same time maintaining our strong balance sheet. Second, focus on operational execution. SM has a track record of optimizing well performance through innovation and technology along with driving capital efficiencies to optimize well costs. Expect more of that in 2023, which I will elaborate more about in a few minutes. We also believe that excellent safety and environmental stewardship are key components of being a premier operator, and compensation for all employees is tied to meeting top quartile metrics. Our third priority in 2023 is to continue to focus on replacing and building our top-tier inventory. We have among the highest quality and longest duration inventories for a company our size. As I have emphasized in the past, our team has been highly successful in applying and in-integrating geoscience, reservoir engineering, and completion modeling to build our top-tier portfolio and deliver best-in-class well performance. Repeating these efforts over the coming years is an exciting source of value creation. I will now turn it over to Wade to talk more about our 2023 strategy and plan. Wade? Thanks, Herb, good afternoon. I'll begin on slide five. As Herb indicated, 2022 was a pivotal year and sets the foundation for what we call a sustainable and repeatable future. We are a premier operator of top-tier assets, delivering a sustainable return of capital. Empowered by our strong balance sheet and world-class technical team, we're poised to repeat this success. Moving to slide six. In 2022, we generated record free cash flow of $849 million. The allocation of that $849 million was predominantly to debt reduction. We used $585 million to reduce debt, effectively transferring that enterprise value to the equity holders, and we returned $77 million directly to stockholders in the form of dividends and share buybacks. Having reached that pivotal point of achieving our leverage targets in 2022 gives us increased flexibility in 2023 to allocate more free cash flow to return of capital to our stockholders. Herb has provided our strategic objectives for 2023, so let me give you the nuts and bolts of how we get there. I'm now on slide eight. Our methodology of developing the plan is consistent with recent history. We create several scenarios and then select a three-year plan that optimizes free cash flow over the period, and then pull out of that the current year plan. Under this methodology, production is an output. As always, we mark-to-market our plan for strip in early February. This year, the lower near-term pricing for natural gas and Contango going forward led us to modify the plan to allocate a higher percentage of capital to Midland in 2023. The plan is run at $80 oil, $3 natural gas, and $34 NGLs. The capital allocation is approximately 60% to Midland and 40% to South Texas, including facilities. We expect to drill about 40-45 net wells in each Midland and South Texas, and complete around 50 net wells in Midland and around 40 in South Texas. A little color on each program. First, in the Midland Basin program, we will test additional intervals, continue delineation of the Wolfcamp D, and test certain completion optimization. The Midland program also assumes larger pad groups averaging around 6 to 8 wells, which as you know, is highly capital efficient and better enables simul-frac operations, but makes the quarter-to-quarter production volumes lumpier. In the South Texas program, we will continue to further the work of our geosciences and engineering teams in well optimization, completion design, capital efficiency, and inventory extension through interpretation of pilot data gathered in 2022. We will also continue design testing and geologic modeling, as well as integration of machine learning. Finally, we will continue to work with our midstream partners to upgrade facilities to handle the higher liquids content we are producing from the Austin Chalk, converting a wet gas system to an oil and gas system. During the fourth quarter 2022, curtailments or deferred production due to high line pressure totaled around 0.2 MMBOE. These constraints are expected to be largely mitigated by mid-year. Expansion of the backbone will be completed on a parallel path with increased oil volumes over the coming years. The guidance numbers are presented on the slide and include capital guidance of about $1.1 billion. For your modeling, this is weighted more to the first half of the year. Our guidance bakes in 17% inflation year-over-year. Importantly, we continue to have very high quality equipment and crews, and have excellent relationships with our drilling rig and pressure pumping providers. In fact, we have worked with Ensign and Patterson Pioneer on the rig side for 10 and seven years respectively, and worked with NexTier Alamo for completions for six years. Production is estimated at 144,000-150,000 BOE per day, representing essentially maintenance level production. The oil percentage will vary by quarter depending upon the timing of completions, and is expected to average around 43% for the year. The cadence of production is expected to include a slight step down in total production in the first quarter, then slightly increasing each quarter through the year, with oil production peaking in the third quarter. As I mentioned, we ran the plan at $80 and $3. Resulting free cash flow will have notable upside to a more favorable commodity price environment, while the return of capital program is sustainable at much lower commodity prices. A rough rule of thumb for you, a $5 change in oil prices results in about a $90 million change in free cash flow. That assumes NGLs trade at their current% of oil, and a $0.50 change in natural gas prices results in about a $40 million change in free cash flow. LOE ticks up to $5.75-$6 per BOE, assuming more workover expense as well as some inflation. Transportation expense drops to $2.50 per BOE, which reflects new processing agreements that go into effect in July. Transportation is expected to average closer to $2.90 per BOE in the first half of the year, declining to around $2.15 per BOE in the second half of the year. Regarding taxes, under our commodity price assumptions, cash taxes are expected to be in the $10 million area in 2023. Turning now to Slide nine, the balance sheet is in really good shape. We're starting 2023 with about $1.1 billion of net debt after returning $76 million to stockholders in September through December. At year-end, the net debt to Adjusted EBITDA's ratio was 0.59 times, and liquidity was $1.7 billion. We have great coupons and a nice maturity profile with bonds faced out and nothing maturing until mid-2025, and the undrawn revolver doesn't mature until 2027. Let's briefly look at year-end reserves. Let's skip to Slide 11. We ended 2022 with 537 million BOE approved reserves, just shy of the company record of 548 million BOE in 2014. This is actually remarkable considering that we were running on average 15 rigs in 2014 and only five rigs in 2022, and the SEC 5-year rule applies now. That's just another positive from top-tier assets. Approved reserves translated into a pre-tax PV-10 value of $12.2 billion. We replaced 205% of 2022 production, excluding the benefit from price revisions. Turning to inventory on slide 12, SM truly has top-tier inventory. We estimate 10-13+ years, assuming 80-100 completions per year, which is substantial for a company our size. We base this inventory on flat pricing of $65 oil and $3.25 gas, and the average return is calculated at greater than 60%. Importantly, nearly 80% of inventory has reserves assigned that are classified as 3P reserves. All wells within our 3P reserves estimate are economic, have an area-specific type curve, a defined lateral length, are at optimized well spacing, and have an assigned spot on the latest developer schedule. We believe this type of inventory assessment could be more rigorous compared to other operators who assume broad brush stroke assumptions of wells per section or shorter laterals over a leasehold area. Wrapping all of that up, we enter 2023 in a very good position. Premier operator of top tier assets delivering a sustainable return of capital and empowered with a strong balance sheet and world-class technical team, we're poised to repeat the success. On that note, I'll turn it back to Herb to highlight operational performance in both Midland and South Texas. Herb? Thank you, Wade. Skipping ahead to slide 15. On the topic of inventory, you have seen this slide before, which depicts the various zones in our Midland Basin assets. Our 2023 plan includes additional testing and/or delineation of the Leonard, Dean, and Wolfcamp D, all zones that we believe offer upside to our current inventory. Specifically, there are 6 Leonard tests planned for the first half of 2023, and we brought two additional Wolfcamp D wells online in the fourth quarter of 2022 and plan seven Wolfcamp D wells during 2023. Turning to slide 16, we show production outperformance of SM wells in Howard County. The chart on the left shows cumulative oil production curves for SM wells in Howard County for the past 20 months against the average oil production curve of 15 peers over the same time period, assuming normalized lateral lengths. On average, the SM wells produced 31% more oil. The chart on the right drills down to SM specific data. This includes all SM wells drilled during each time period and shows cumulative oil production for SM completions in 2020, 2021 and 2022. The black line denotes the significantly improved performance from our 2021 wells versus 2020 wells, primarily due to the new completion design with larger stimulations. As we talked about last year, this is an outcome of our differential application of technology. The green line shows our 2022 wells, and here you'll see that they're just now meeting the 2021 curve. This is what we talked about last quarter and is in large part a result of deferred production stemming from offset activity. At the time, we pointed out that offset activity affected 20% of new Midland wells in 2022, but was not going to have a long-term impact on well EUR performance. You can see that now. Turning to slide 17, we show EUR performance in Howard County. This third-party data set indicates the average oil EUR per 1,000 feet of lateral for SM and 12 peers in the area. SM EURs rank the highest, and this compares to larger peers and peers who do not co-develop similarly to SM. I will note that even a few% increase in EUR makes a difference in well economics. Here, the lowest peer stands at 31,000 barrels per 1,000 feet, while SM sees 52,000 barrels per 1,000 feet. This quantifies what we are doing from a technical standpoint to yield top-tier well performance. Moving on to South Texas and skipping to slide 19. We now have 68 Austin Chalk wells on production that have reached their IP30 and have updated our cumulative production curve to include all these wells in the figure on the right. On the left, we highlight 14 Austin Chalk wells in the liquids rich gas area that have reached IP30 since October 2022. Peak IP30 rates average an excellent 2,500 BOE per day with 30% oil and 64% liquids. Turning to slide 20, here we drill down and show the cumulative production curves on a BOE basis comparing our high oil content area wells to our liquids rich gas area wells. The significant difference in the cumulative curves represents the difference in the commodity mix. To the north, we see higher oil content wells, and in the liquids rich gas area, we see higher BOE volume wells. While the cumulative production curves are very different on a BOE basis, the payouts from each area have historically been consistent, but can vary depending upon changes in oil, gas, or NGL prices. The oilier curve represents 18 wells, 14 in the middle Austin Chalk and four in the lower Austin Chalk as we commence co-development in the area. Each bench offers excellent returns. Based on the January 31 strip, the lower bench is estimated to have a 75%-80% rate of return, with the middle bench at over 100%. Let's go back to the science and my favorite slide, 21, from last year, which has been updated to reflect nearly twice as many Austin Chalk wells on our acreage. Our Midland Basin and South Texas Austin Chalk wells are highly predictable. The P10, P90 ratio shown is simply the ratio of the EUR of the best 10th percentile well to the EUR of the well that sits in the 90th percentile of the EUR distribution of the 68 wells. This is a commonly used measure of repeatability. In this slide, we've shown the P10, P90 both per well and per lateral foot. We have a larger range of stimulated lateral lengths in South Texas than in the Midland Basin. As you'd expect, this results in a slightly larger range in the P10, P90 between per well and per foot in South Texas. The results we have here are similar to those of outstanding resource plays like the Midland Basin, especially when you consider the oil versus gas condensate range of our play that affects barrel equivalents. As you can see, our Austin Chalk wells are substantially more repeatable and predictable than the old Austin Chalk wells from East Texas. Let me just close by reinforcing what we've talked about today with slide 22. We are focused on a sustainable and repeatable business model that is characterized by outstanding operations, a strong balance sheet, growing return of capital to stockholders, and strategic inventory growth. Thank you for your interest in SM Energy, and I look forward to our Q&A call tomorrow.