Good afternoon, everyone. Jim Felton here with EnerCom. Thanks for a great morning. We are looking forward to a great afternoon. I would like to start off the afternoon by saying eyes up, phones down. You all had a good enough time to check on all that that is urgent and usually superfluous. We will jump right in here with Amplify Energy. They are an independent oil and gas company. They are focused on the acquisition, development, and optimization of producing assets focused in Beta, which is the Pacific Outer Continental Shelf, and Bairoil right here in the Rockies. We are fortunate enough today to have their CEO, Dan Furbee, giving us the latest. Dan, thank you. Thank you. All right. Thank you for the time here. If you followed our story the last few years, the company looks a lot different today than it did a year ago. This time last year, we talked about a new strategic plan where we are going to simplify the portfolio. As you know, a year ago, the company was an old MLP. We had kind of scattered assets throughout the U.S., not a tremendous amount of scale in any one place. We found it prudent to simplify the portfolio. By doing that, we sold our East Texas, Oklahoma, and Eagle Ford positions, net proceeds about $250 million. Strengthened the balance sheet by paying down all our debt. We currently have cash on hand to execute our programs going forward. Our programs we are talking about is we are focusing on our remaining two assets, which feel like has the greatest value creation potential of the assets we had here and just a lot of upside with these two really unique assets. We will talk a lot about them. The Beta asset, we are currently drilling there offshore California in federal waters, and our Bairoil asset, which is an active CO2 flood that has traditional oil and gas expansion through tertiary recovery opportunities, but also some very interesting CCUS opportunities, which we are taking advantage of. Additionally, just a couple of weeks ago, we announced a buyback program. We will talk in a minute about how our current trading value looks extremely cheap compared to our company's intrinsic value. With that, the two assets we have remaining, two mature, prolific oil fields, really unique assets. The Beta asset is offshore Pacific OCS waters. We are one of three operators in federal waters offshore California. Mature field discovered in the late 1970s by Shell. The field has produced more than 100 MMbbl of oil to date. We will talk about the geology and our development program in just a minute, but it has been a very good field for us so far. We are developing the field, the first one to really develop this field in earnest since the 1990s. It has been exciting for us. Still a shallow decline, even with the development, 10% decline over the next five years, and a large inventory of drilling locations remaining. Our Bairoil field. It is located in the greater Green River Basin in Wyoming. Very mature field, discovered before 1920. It has produced over 340 MMbbl of oil. It has been in a tertiary CO2 recovery since the 1980s. Very long life, very low decline, and we'll talk about those opportunities there. If you look at our mid-year reserve reports, we have a proved developed value, PV-10 value, of just over $400 million. Getting to the company valuation. If we focus on $75 WTI oil, we have approved developed reserves at a PV-10 of $414 million. Our PUD value of Beta at a PV-20 is $106 million, so 1P reserve value of $520 million. Then some other attributes of our value, the mark-to-market, the hedges. We do have a restricted cash account that goes to the Beta sinking fund, which eventually goes to decommissioning of our offshore assets. That's in addition to we capture the full value of our decommissioning costs in our reserve reports as end-of-year proved developed value as well. So that's why we add this value here. You'll see we add $9 million- $10 million a year. That account is growing as we develop. Cash at the end of the second quarter, then a [DDOC] for a multiple of our G&A run rate. So implied equity value of $510 million would imply over a $12 share price, more than a 200% premium to our recent trading value. I talked about before, this is the main reason why we instituted the buyback program a couple of weeks ago. In addition to all of this, we'll talk a lot about the other upside here. The Beta asset, what we don't have booked as SEC PUDs is extensive, then the opportunities at Bairoil. Dive into Beta a little more. So it's three federal leases, federal blocks, about 10 mi offshore Southern California. If you're in between Long Beach or Newport Beach and on a clear day, you can kind of see the platforms on the horizon. We have three platforms. Two producing platforms. It's our Eureka platform and Ellen platform. Between the two of them, we have about 120 slots. Sorry, about 140 slots, and we have about 90 producing and injecting wells. So it's an active water flood and with the production as well here. We own our drilling rigs. We have a drilling rig on each platform, which was installed back in the 1970s, and we'll talk about how some of the upgrades we've done to these rigs allow us to drill the wells we're drilling today. Then we have Platform Elly, which is our processing platform. All oil, water, gas goes to that platform, separation, treating, and then we send our sellable oil through a pipeline right into Long Beach. From there, we're connected to the L.A. Basin oil refinery complex. A little on the geology. So Beta, large oil accumulation, about 1 billion barrels of original oil in place initially. This field is very analogous to other L.A. Basin oil fields. Very good rock, mostly heavy oil. When you look at these analogs, typical recovery factor is 30%-40%. Beta's recovered 10% to date, so about 100 MMbbl of oil. Gives you an idea of the ultimate upside of this field. When we look at historic development, and you look at the type log here, most of the wells here have been drilled through the A through F sand and commingled, and we'll talk about the inclination of the way they drill these wells historically to what we're doing now. But essentially now we're drilling horizontal wells through each individual zone, and we're starting with the D sand. Of the zones, the D sand is our primary target. Thickest reservoir, best rock, great permeability, and it's delivered some great results so far. Legacy development. Of the 120+ wells been drilled here, almost all of them drilled in the 1980s, early 1990s by Shell. At the time, they drilled these wells as high-angle wells, really not to exceed 30- 40 degrees inclinations. Reason for that is these are unsalted sandstones. Drilling horizontals through these back then before they had top drives, rotary steerables, advanced mud systems, really hard to do. What we're able to do now with the advanced manned rigs and using state-of-the-art rotary steerables, measurement while drilling, logging while drilling, we're now drilling horizontal through these wells. We're accessing parts of the field that they couldn't access before, and that's what's created the most opportunity here. A ton of oil in place, you'll see in the southern end of the field, they just couldn't drill before. It's created a ton of opportunity. These are results so far. We've drilled nine wells since the start of the drilling program in the middle of 2024, and eight wells in the D sand, one well in the C sand, and production's grown about 2,800 bbl net production per day to the midpoint of our guidance this year is about 4,500 bbl. About a 1.5x over three years, drilling nine wells. And you'll see with our drilling inventory and the development we have in front of us, we expect to continue to grow that. A little more on the asset and the field. We kind of break this asset into two fault blocks. To the north is the main fault block. This is where most of the development was in the field historically. We drilled two horizontal D sands here thus far. This is an area that's heavily water-flooded, heavily developed. Success here is identifying where the unswept oil is, and if you find that unswept oil, you're going to find more than likely over-pressured, high oil saturations, deliver big initial results. And then we have the Joulters fault block. This is the area that's very underdeveloped, and if you just look where those wells are drilled relative to where the two producing platforms and drilling platforms are, this gives you an idea that they just couldn't get there back in the 1980s. That's what's created a lot of opportunity here. This is largely undeveloped, virgin pressures, predictable oil saturations, and it's where most of our PUDs are located. Dive into the Joulters Block. If you look at the porosity thickness map here, the D sand, see fairly consistent across the field. We've seen fairly consistent results. We've been able to map the oil water contact, the southern end of this field, as we use pretty advanced logging while drilling tools. We're essentially able to see about 100 ft above and below us in the sand to read resistivity. The furthest well we drilled south, the C-16 well on the southern end of this map, we are able to extend the oil water contact to where you see it arrowed on this map. That's increased the number of well locations we can put down here. The Joulters fault block in general, about 70 MMbbl of oil in place just in the D sand. If you assume 30%-40% recovery factor, you're talking 20 MMbbl-28 MMbbl of oil to recover. Drilled six wells so far. We've mapped out 19 additional wells assuming an average lateral width of 1,200 ft. That's what we've been doing generally. Now we may extend that eventually. That reduced number of locations, but should see bigger EURs per well. The results per well, you see our type curve here. We're using 500 bbl/d for an IP gross EUR, about 670,000 bbl of oil. Our average capital cost per well is around $6.5 million. So excellent returns. You can see the results. Some wells really outperformed type curves. Others are slightly below rate on it. But on average, we've seen pretty consistent results in this Joulters area, and like I said, we have 19 additional wells to drill here. The main fault block, the main fault block's really interesting. Like I said, if you can find where the oil is unswept, you see some big results. We drilled two wells so far. I'll point the A50 well graphed here. This well is only a 200 ft lateral. Reason being, we drilled 200 ft into it, then we saw water in front of us. It's hard to predict exactly in this fault block where it's going to be swept. So we cut the lateral short. We actually put a swell packer at the end of the gravel pack completion, blocked off the water, worked very well. Well came on about 1,000 bbl/d. Declined relatively quickly. It's only a 200 ft lateral. But still turned out to be an excellent well. The C-61 well was really the only laggard we had in our D sand development so far. This is a well we drilled into a fault, ran completions, didn't get a good gravel pack on our screens and turned out okay, but as you can see, the worst well we drilled so far. But main fault block in the D sand, 400 bbl/d IP, just over 500,000 EUR. Still excellent results. Not as many wells to drill here, but the ones we do plan to drill here, we think they have really high potential. Just going over our D Sand current inventory, like I said, 19 wells and Joulters, seven in the main. Just point out, this does not include any upside for F Sand or C Sand potential. We hope in the near future, drill a horizontal well in the F Sand to test that zone, as there's no reason to believe it won't come on similar to what these D Sand wells come on at. Another good development for the company and for Beta, earlier this year, qualified for royalty relief. I will say BOEM and BSEE, especially under this administration, very easy to work with. Some of these incentive programs you have on the federal leases offshore. Essentially, we took a 25% royalty burden and lowered it 12.5% on the majority of our production. So our weighted average royalty burden is much lower now. We think there may be other opportunities here to enhance the economics of the Beta field just through these royalty programs. On to Bairoil. Bairoil, very different than Beta, but like Beta, we think a ton of upside and just a very unique asset. Producing just under 3,000 bbl/d net. Like I said, it has been CO2 flooded since the 1980s. You can see where it is located on this map to the top right. Essentially, we are right off the main CO2 transmission line running right through central Wyoming. Looking to the west, the supply of most of this line is coming from Shute Creek, operated by Exxon. We are connected to the CO2 line, and we get CO2 delivered to us through this line. In addition to flood expansion we will talk about through the CO2 flood, there are a lot of CCUS opportunities related to 45Q tax credits that we are receiving some benefit from in the Bairoil field. Most of that benefit has come from, so far, an updated CO2 contract. At Bairoil, we operate and we recycle about 200 million a day of CO2. We purchase or had purchased about, as you see on the graph there on the right, about 10,000 Mcf a day of CO2. Now, typically, you have to pay for the CO2, whoever is providing it. However, last year, we went through the process and got our field certified under ISO EOR Operations Management Plan certification. What that means is any qualified CO2 you put in the ground in a certified reservoir, you have the opportunity to earn 45Q credits. A qualified CO2 is essentially anthropogenic CO2 that is captured that otherwise would have entered the atmosphere. 45Q credit days, $85 per metric ton. That is about $4.50 per Mcf. You can see from the volumes we move here, it is a pretty meaningful amount of value. Essentially our new contract, the supplier of the CO2 benefits from claiming that 45Q credit that is going to our certified field, and then we get a portion of that economics through a rebate. Before the contract, we were paying about $5 million a year for CO2. Now we are receiving about $5 million-$6 million a year of CO2. So a $10 million swing on this asset. I will say, we hope and we anticipate this could just be kind of the start of this value related to CCUS 45Q credits, as the Bairoil field is located in a kind of opportune area for this type of venture. We have an immense amount of pore space in this field. Very big field, as you saw, 340 MMbbl of oil have been produced to date. Most of that space has been taken up by water now, but that water can be evacuated, can make more space for CO2. With the contract, we are now getting a lot more CO2. We went from about 10,000 Mcf a day to about 32,000 Mcf a day. With that CO2, given that we do not have to pay for it, we can do some other interesting CO2 flood expansion type of things. For example, in our Wertz field here, you will see we have five sectors here across the Wertz field, the way we identify them. Four of the five sectors has had about two times the pore volume injected in terms of CO2 injection into the reservoir. They have recovered over 20% incremental recovery since CO2 injection started. Then we have the laggard here, sector one to the north, has only received 0.3 pore volume to CO2. It was always contemplated by the company to enter into a new CO2 contract to get more CO2 and pay more money every year to inject more CO2 into this part of the field. It makes the decision a lot easier now. It is free CO2, so we hope to start injecting CO2 into this part of the field. You can see just simple math, we have 18 MMbbl of oil in place in this sector one part of the field. If we only receive a 10% recovery, which would be the minimum compared to the other parts of the field, that is 1.8 MMbbl of oil cumulative production with no additional CapEx or operating costs. That is an exciting development, not included in the company's reserve, not included in the values we looked at earlier. Then overall cost for Beta and Bairoil. Company has been doing a great job lowering costs. Both these assets are relatively high fixed cost assets, so dropping costs by 15% is immensely accretive to the bottom line of each of these assets. Most of the savings come from that $10 million savings from the contract we talked about at Bairoil, but a lot has come from other parts of Bairoil and Beta as well, as that $10 million is only a mid-year thing this year. I think I am at the end. Oh, there we go. Lastly, just touch on another benefit of simplifying the portfolio like we talked about early on. A lot of smaller assets kind of spread throughout the country, especially East Texas assets with immense amount of leases and division order and all the back office support you need with all those types of assets. We have been able to reduce our G&A costs quite a bit. Our G&A head counts reduced more than 50%, and overall G&A costs from 2025- 2026 to where we expect to be in the run rate for 2027 is significantly reduced. The company is doing a good job of trying to hit every part of the cost structure. With that, I will wrap it up. In general, we have two, like I said, unique, interesting assets. I think they have a ton of upside. We think even without a lot of that upside we talked about, we are trading at a very steep discount to the intrinsic value of the company. With that, I think we will be in a breakout room for any questions. Thank you.