We're hedging because we're protecting the cash flows that support dividend and our ability to invest through the cycle. This is one of the more interesting develops that you'll hear a lot about today, and it's about the efficiencies of longer laterals. Every well seems to be getting longer, and importantly, the economics are improving with them. Since 2022, the average lateral length on the wells we're participating in has increased 38%, and nearly 70% of the wells we're participating in in 2026 are 3 mi or longer. We're also seeing EUR continue to scale on a per foot basis while drilling and completion cost per foot decline. Our data shows median D&C from a 2 mi to a 4 mi lateral is about a 25% reduction on a per foot basis. The second benefit to these longer laterals is decline. As longer laterals are a larger portion of our overall production base, we expect to help reduce our overall corporate PDP decline. A lower decline rate means less reinvestment is required to maintain that production, which leaves more free cash flow available for other uses, including the dividend. That's really what matters to us. We don't pursue technology simply because longer lateral wells are interesting. We care because capital efficiency and lower reinvestment requirements overall improve returns. Talk to you more about Illuminous. There's so much going on about AI in the industry, and that's obviously real. Our Illuminous system actually predates the current AI enthusiasm. It's our proprietary platform and essentially our single source of truth across accounting, land, finance, engineering, and operations. We've taken all the data from all those wells, the production, AFEs versus actuals, lifting costs, et cetera, and consolidated that. Illuminous really helps us understand those production, the cost, the economics on an individual well level, and more importantly, it allows us to integrate additional assets without growing the organization at the same rate. Today, we have 35 employees that manage, like I said, the 7,800 wells. That's roughly 225 wells per employee. It's pretty decent. Since 2022, our production's increased and our G&A per BOE has declined. We like that stat. To me, that's one of the clearest measures of scalability of the platform. As the asset base grows, we expect more of that incremental value to accrue to shareholders rather than being consumed by additional overhead. I'll finish with what I think ultimately defines Vitesse. We have a long duration oil-weighted asset with significant undeveloped inventory. We have a highly scalable business model. We have interest in over 7,800 wells and exposure to some of the best operators in the Williston, Powder River, and DJ basins. Assets alone aren't enough. What matters is what we do with them, and that's where the discipline comes in. We're embracing discipline, how we underwrite investments, how we manage the balance sheet, as well as commodity rev- [Break] Thank you. As Andrew said, Epsilon is a multi-basin, multi-product portfolio. We have diversified investment opportunities that allow us to target projects with either the best returns or the highest strategic value to the company, whether that be operated or non-operated, crude oil or natural gas, or conventional or unconventional. We have attractive opportunities for capital allocation across our portfolio as what we define as priority one inventory. Of this, we have 115 net locations, which equates to over a decade of development inventory meeting this criteria. Additionally, we have more opportunities that exist that don't meet this criteria simply because of the less than 45% working interest, which was a threshold that we have used internally. That being said, via trades or partnerships, this inventory could be pulled forward and developed sooner. Additionally, we have the opportunity to move more inventory, such as the Powder River Basin shales, into the priority one with economies of scale through a development program. Of the 115 net priority one locations, you can see these are spread across either our legacy non-op natural gas in the Marcellus, which is operated by Expand, our non-op crude oil in the Permian Basin operated by Firebird, which is a successful PE-backed company, or our newly acquired operated oil and natural gas targets in the Powder River Basin. Overall, we have diversified an asset base that allows us the ability to deliver attractive returns to our investors. As Andrew said, the assets in the Powder River Basin were acquired in late 2025, and this added in the operated assets to our overall portfolio. The assets are primarily located in the southern Campbell County, but we also have a very nice federal drilling and spacing unit in Converse County. The acreage is directly offset by premium public and private operators such as EOG, Devon, and Anschutz Energy. Along with this core acreage and producing wells, we were able to retain a highly experienced management team that has operated these assets for many years. This team has drilled and completed over 100 horizontal wells from five different formations. The experience that we got with this team allows us to basically skip the learning curve that might be associated with entry into a new basin. Overall, we have about 40,000 net acres in the basin, 31,000 undeveloped, 75% HBP with no continuous drilling clauses. This is important because it allows Epsilon to be very targeted and patient and selective with our development plan. We have, again, both conventional and unconventional targets of oil and gas in the basin. In the first half of 2026, as Andrew said, we successfully completed two Niobrara DUCs, and we're very pleased with these results as they have met or exceeded our internal expectations. In the second half of the year, we've already successfully drilled three Parkman laterals, which are going to be completed this month. In addition, we're going to begin construction of water facilities in Converse County to support future development down in that area. The Powder River Basin will be an important and productive basin for Epsilon for many years to come. With that, I'll turn it over to Paul Atwood to speak about the other great investment opportunities that Epsilon has. Good morning. I'm Paul Atwood, VP of Finance for Epsilon, and I'm happy to be here with you this morning to describe some exciting opportunities for our business. I've been with this company for 15 years, and this is undoubtedly the most exciting time since I've been working for the company. I'm going to provide a brief overview of our Permian assets and our Marcellus assets, then jump in to demonstrate some of the impact that the near-term development's going to have on our business. Our Permian assets on the Central Basin Platform in Ector County, where we have a 25% working interest in a 16,500-acre leasehold targeting the Barnett Shale. As Andrew mentioned, we've participated in nine well bores to date, with each of those meeting or exceeding our pre-spud type curves. I think we have a very good understanding of the reserves and the liquids cuts of these wells. I think there's really two key takeaways from this slide. The first takeaway is the majority of our leasehold is undeveloped. Of that 16,500 acres, 13,000 is undeveloped. We still have 30 Barnett locations remaining to drill, gross locations. The second takeaway is that this asset is now operated by Firebird II. That happened earlier this year. Firebird is a much more scaled operator than we had, and the activity is going to ramp here materially while drill and complete costs will start to head lower. It's a really exciting time for this project in particular. We've already participated in the drilling and completion of one Barnett well this year. We're going to drill two more in the second half of the year, and we'll have completion operations on those two wells in Q1 of 2027. The last thing I want to mention on our Permian asset here is that the operator drilled a Woodford test well on our leasehold this year, with completion of that well will happen in the second half of the year. We actually non-consented the well, so we did not participate, but we have full exposure to the Woodford through our leases should the test be successful. We're excited to see how that turns out. Epsilon has a 5,100 net acre position in the Marcellus, and we've had it for a long time. We actually took the leases back in 2005 to 2006, 2007. We've been up here for a long time. Expand farmed into our acreage back in 2010, 2011. We're in southwest Susquehanna County. It's been a core position for us for a long time, and it will continue to be a core position for us. Over the past 15 years, we've participated in the development of 146 wells with Expand Energy, who's proven themselves to be a superior low-cost operator. Despite all of the sticks and development that you see on the map, Epsilon still has about 450,000 gross or 100,000 net lateral feet of development remaining here. I think the impact of this asset to our business should not be overlooked. We talk about it as a legacy asset, but in fact, we estimate that we have approximately 170 Bcf to 200 Bcf of undeveloped net reserves here still to get. That's a massive impact for our business. We drilled five gross wells this year, but only 0.4 net, which will be completed and turned in line in Q4. Next year, we expect seven gross wells, 1.4 net, so we're going to have, again, a step up in net development in this asset next year. Also here in northeast Pennsylvania, we own a 35% undivided interest in our gathering system. It's called the Auburn Gas Gathering System. This system gathers all the gas inside the target system boundary that you see and brings it south down to our compression facility, which sits on Kinder Morgan's Tennessee Gas Pipeline 300 Line. This gathering system is supported by about a little over 1 Tcf of gas from ourselves, from Expand, from Equinor, which is really pretty amazing because the compression facility went live in October of 2013. We've already processed 960 Bcf of gas in the last little over 10 years, 12 or 13 years. We have more than 1 Tcf in reserve still dedicated to the system. If you've been following the Epsilon story for a while, we used to operate this midstream system under a cost of service contract. That's no longer the case. We transitioned to a fixed rate that escalates annually at CPI. It's really a good business. Our EBITDA margins here are 65%-75%+, kind of depending upon throughput in the system. We have capacity for 150 million a day at our compression facility today. But we're currently reviewing an expansion process at Auburn to accommodate the development that we see in 2028 plus. I think the key takeaway here is that there's material upside to our midstream earnings with development inside Auburn. Okay, there's a lot going on on this slide, so I'll try to do my best to describe it to you. We've spoken in this presentation today a lot about the inflection of development pace that we expect from acquiring an operated position in the Powder, from having a new scaled operator in the Permian, and from a return to meaningful net development in the Marcellus. What we really wanted to do with the next few slides is kind of demonstrate how this near-term development can really impact our business. The next two slides will demonstrate that impact, and it shows representative single-pad development from each of our assets with our average working interest that we have. On the left on this first slide is a four-well Upper Marcellus pad. The development of 56,000 lateral feet in which Epsilon has on average a 25% working interest. This is a representative pad of our remaining Upper Marcellus inventory. In the first year, this pad will produce 4.7 Bcf net to our revenue interest and $9.6 million in operating cash flows, and that's at $3.5 Henry Hub with appropriate Zone 4 basis. With a net capital investment of $10.8 million, we expect to recover almost 90% of the capital investment in the first 12 months. That's how good these Marcellus wells are. As I mentioned before, in 2027, we expect our operator to develop seven gross, 1.4 net. What you're looking at here is only really is one net well, so an impact greater than that. The chart on the right is our midstream system, and it demonstrates the kind of sensitivity in our earnings of our midstream system to incremental development in Auburn. Year to date, we have only processed about 94 million a day through our system on average. A single four-well Upper Marcellus pad inside Auburn will add approximately 60 million cubic feet of gas per day on average for the first 12 months of the year. We can really slide, if you look at the left side of that chart, 100,000 a day, we are just below that. A single pad development pushes us right in the middle of the chart, increasing our midstream earnings over 50%. Very impactful to have that development in Auburn. Moving from the Marcellus to on the left is the representative Permian pad in Ector County. On the right is a Powder River example. I am going to step through these. Similar to the previous slide, we are trying to demonstrate our leverage to this development and these assets that we have highlighted today. On the left is an example of a four-well development of a 67,000 lateral feet pad in the Barnett. Recall that I mentioned earlier in the presentation, the majority of the leasehold here is undeveloped. As we understand our operator's plans, the majority will be developed along a corridor drilling 3+ mi laterals north and south. You are looking at this is a representative pad of a 3 mi north and south development. In the first 12 months from this representative pad, we expect to produce 242,000 BOE net to our revenue interest, and $10.8 million of operating cash flow at $70 crude and $3.50 gas. With a net investment of $14.8 million, we would expect to recover almost 75% of the capital deployed in the first year. Moving to the right panel is a three-well Parkman example of 26,000 gross lateral feet in Converse County, which is where we are going to be increasing our activity in 2027. In the first 12 months from this representative pad, we expect to produce 360,000 BOE net to our revenue interest, and $18.5 million in operating cash flow at $70 crude and $3.50 gas. Again, the net investment here is $16.5 million, so we are recovering more than our capital outlay inside 12 months. Just a phenomenal opportunity for our business. I am going to hand the mic back to Andrew to discuss our 2026 guidance. Thanks, Paul. The last slide here is a preview on the growth that I mentioned at the beginning of this presentation. We recently, last week, along with second quarter earnings, provided some guidance for the third quarter and the full year. I will highlight a few things, the first being what that looks like in terms of production growth year-over-year. The midpoint of our guidance represents 18% year-over-year growth. The other important figure here is the oil cut. We have increased year-over-year oil with the Peak acquisition and development we have seen in the Permian by almost 200%. Back to what I said before, over a multi-year growth period for the business, this is going to continue. We see the same type growth in the next several years as well. The way that we think about that is if plans change from our operated partners on the non-op assets, we pick up the pace on the operated piece in the Powder. We look forward to continuing to deliver good results, starting with full year and second half this year, carrying on into 2027, with fundamentals leading the way for us for shareholder value. Thank you very much.