Amplify Energy Corp. EnerCom Denver – The Energy Investment Conference

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 million barrels 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 million barrels 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 to $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 miles 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 million barrels 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 plus wells been drilled here, almost all of them drilled in the '80s, early '90s by Shell. At the time, they drilled these wells as high-angle wells, really not to exceed 30 to 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 barrels net production per day to the midpoint of our guidance this year is about 4,500. 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 '80s. 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 feet 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 million barrels of oil in place just in the D sand. If you assume 30%-40% recovery factor, you're talking 20-28 million barrels of oil to recover. Drilled six wells so far. We've mapped out 19 additional wells assuming an average lateral width of 1,200 feet.

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 barrels a day for an IP gross EUR, about 670,000 barrels 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.