Our next presenting company is Amplify Energy. They're a Houston-based company, mature legacy fields with operations in Oklahoma, the Rockies, offshore Southern California, East Texas, and North Louisiana. Here to talk about the company is Daniel Furbee, their CEO. Please welcome him.
Thank you.
Thank you. We'll go through this. Like he said, we are a diverse, low-decline, long-life E&P company. We have four different operating regions currently. We'll talk a lot about the one on the top here, the Beta asset, which is our offshore Federal Waters, Southern California asset. We have our Bairoil asset, which is in Wyoming. It's a CO₂ flood, very mature, predictable asset, 100% oil. We have an East Texas, North Louisiana asset. This is a partly mature, well-count, large footprint producing from all the historical horizons you see in East Texas. We also have very attractive Haynesville acreage, especially as the Haynesville play continues to move to the west into our position. We have several joint ventures. We've been farming out our position in some of the Haynesville acreage and participating in wells with some of our operating partners. We have an Oklahoma position.
This position is the Mississippi Lime position. We've owned this since 2019. It's a very efficient operation and a lot of upside here as well, which we'll talk about our intention with those assets shortly. Our enterprise value is just under $300 million and market cap of between $150 million and $160 million. Moving on, this year will likely be a transformational year for the company as we recently sold one of our positions, a non-op Eagle Ford position. We sold in the second quarter, generated $23 million net proceeds, and then we recently announced our intention to market our East Texas, Oklahoma positions. We intend to take business positions later this quarter. The strategy of the company going forward if successful with the divestitures is to simplify the structure and focus on our Beta position and also Bairoil. We see a lot of upside there through cost-cutting initiatives.
Point to a few other things on this slide. We'll point you to the middle of the slide and shareholder value creation. Our last Beta well we brought online is producing 850 bbl a day currently. It's been online for four months. We target to drill these wells for approximately $6 million. These are very attractive projects, and we continue to accelerate that program. We also participated in four non-op wells in East Texas with one of our partners. That well is currently producing 13 million a day to our net interest, and we have about 25% interest in those wells. Two of those wells were Cotton Valley, two were Haynesville. It goes to show the productivity of the Haynesville wells in our portion of the acreage.
We generate free cash flow this year, even with the selling of the East Texas positions and the Oklahoma, or sorry, selling the Eagle Ford position thus far. We also sold some of our East Texas acreage that's brought in proceeds above and beyond the free cash flow we intend to generate. We've been investing in our Beta position, a lot of facilities investment to accelerate that production, and a lot of drilling at Beta thus far. Capital discipline, we've reduced our debt by $6 million from year-end 2022 to current and brought our leverage down significantly. Talking about our current valuation, we're just under $4 per share. At $60 oil, assuming PV10 for PD and our POD value at PV20, we're looking at $6 per share and at $65 and over $9.
We'll talk about in a minute how we don't think this POD value really represents the upside we see in Beta, which is why we've talked about what we're focusing on as we move forward. More characteristics of our assets: very low decline base, so 5% annualized decline. Also our R/P index, 1.3x our peer group. We're looking about 14x R/P at the end of Q2. Our comparison here is at the end of Q1, just about 12x. Very mature, predictable cash flow from these assets. Let's talk about our Beta asset. We started a development program here in the middle of last year, and we brought online four wells so far. Three of the wells, we'll talk about in a minute, are D Sand, which are primary formation, and excellent results thus far. Primarily from those three wells, we've grown our production by 30%.
We're excited about this, and we see a lot of oil in place here to be recovered, and we're developing this field as we move forward. Looking at these three wells, we have a type curve currently we put out in the Beta field of an IP of about 400 bbl a day. That generates just over 500 MBO gross oil, and at a capital cost of about $5.8 million, 90% rate of return is $65 oil. You can see our three wells so far have significantly outperformed this type curve. I'll point you to some of the stats here in terms of gross EUR from these wells. This is the last one we brought online as we continue to get better as we drill these wells. This well's been online for four months. IP'd at 910 bbl a day. This will produce 850 bbl a day.
A very flat decline, which is representative of this field, even with the development. This is a heavy oil but high perm reservoir. We expect to see very little decline as we bring these wells online. Our break-even cost of these wells with our type curve is about $33 per barrel. This obviously competes very well with any area or development in the Lower 48. This data is from wells turned online since 2022 from Embaris. If we step back and look at the Beta field, just a little history of this field, it was discovered in the 1980s by Shell. In the 1980s, Shell came in, discovered this field, developed three platforms, and two of the platforms are production and drilling platforms, with the drilling rigs integrated into the platforms. One of them is a treating and processing platform.
We ship the oil to shore through a pipeline, and we sell right at the custody transport point, right at the Port of Long Beach. You can see here we have the two production platforms. In the yellow squares. A lot of people ask, why now, right? This field was discovered in the 1980s. How is there so much oil left to recover? Why are you guys doing what others haven't? In the 1980s, there wasn't the ability to get some of the wells drilled to where we're drilling. The reason being, we don't show this chart because it'd just be a jumbled mess, but there's about 120 sticks coming from those two yellow dots right there, two yellow squares, those two platforms. From the 1980s to now, what we've done is we've upgraded the rigs. We now have obviously top drives on the rigs, upgraded mud systems.
We also utilize managed pressure drilling, and we have several different ancillary things we've upgraded since then. Use rotary steerables and several different things they didn't have in the 1980s. That allows us to drill a lot of these locations they just simply couldn't drill in the 1980s. Since the 1980s, it changed ownership in the 1990s and early 2000s, and there was some drilling being done at that time, marginal results. We feel like we've really cracked the code here and have done some really good things over the past four wells. When we look at this, we're just showing the 25 pod locations we currently have, and most of those are D Sand locations. When we look at this, we see a lot more upside beyond these 25 pod locations. Here's a type curve of the reservoir.
If you look back in the 1980s, what was typically done, and in the 1990s, some of the limited drilling they did, it was more or less a vertical or low-inclination well and commingled all these formations. What we're doing now is we're essentially drilling horizontally through these locations. We're targeting the D Sand locations. It's got the best pay, and the three wells drilled so far are the excellent results we've seen thus far. Beyond the cumulative production thus far from the field, which you see here is just over 100 million bbl, and the PDP recovery you see remaining, and the pods we have on the books utilizing the type curve we just showed, which of course the results seen so far are quite a bit above that type curve, we expect to recover approximately 120 million bbl from just those 25 pods.
As you can imagine, from the 1980s to now, there's been a lot of studies on this field in terms of the original oil in place. The low end of those studies is about 600 million bbl, the high end is a billion barrels. We also have a lot of analog fields, Southern California, as you know. Onshore and nearshore state water fields have very similar rock and very similar oil characteristics. We see recovery factors of those fields between 30% and 40%. With that, we would expect at the low end of the oil in place estimates to the high end and the low end of the analog field recovery factors to the high end to recover somewhere between 180 million bbl - 400 million bbl. We project after these 25 locations, if they only come in at the type curve, to recover 128 million bbl.
After this pod recovery, we still expect to have between 50 bbl - 170 million bbl to recover. This recovery factor and these reserves left here, the results we've seen over the past year since we upgraded all of our equipment, upgraded our drilling systems, upgraded the way we drill these wells, and we're really the only ones who have ever drilled horizontally through this reservoir. The results we've seen in these recoveries that are remaining is why we get so excited about this and some of the reasons for our strategy changes in the company. With that, we'll go here. Once again, just to go over what we went through before, strong balance sheet, but we think we can grow beyond here through our Beta asset mostly.
Even without the Beta asset development and the growth we've seen so far and expect to see, you know, see a very high equity value, 147% premium to our current share price, free cash flow positive even with the investment put in the Beta before we see the growth that we expect to see through acceleration. Our Beta asset development obviously is where we'll be focusing going forward. I think that's all we got. Thank you.