Amplify Energy Corp. Q3 FY2024 earnings call

Key Points

• Amplify had strong Q3 performance with $25.5M adjusted EBITDA and $3.6M free cash flow.
• Evaluating Wyoming asset monetization but retaining assets for cash flows despite crude price volatility.
• Beta development program progress: C59 well online, C48 expected in Nov, plan to update 2025 program in Q1 2025.
• Sustainability report released, highlighting progress in emissions reduction, safety, etc.
• Production details: Q3 production ~19,000 BOE/day, lease operating expenses down due to optimization.
• Capital investment: $18.2M in Q3, 66% allocated to Beta facility projects and development drilling.

Total Production for the third quarter averaged approximately 19,000 BOE per day. The production commodity mix was 43% oil, 17% NGLs, and 40% natural gas. Lease operating expenses were approximately $33.3 million in the third quarter, a $3 million decrease from the second quarter. Gathering, processing, and transportation costs were $4.3 million, and production taxes were $6 million. Adjusted EBITDA for the third quarter was $25.5 million, and free cash flow was $3.6 million.

Forward-Looking Statements

• Fourth quarter LOE expected to be lower than Q3 and in line with guidance.
• Total capital expected to be at or slightly above the $60M-$65M annual guidance range due to acceleration of non-operated development costs in Q4.
• Borrowing base redetermined: reduced $5M, elected commitments increased $10M to $145M, improving liquidity.
• Added crude swaps for 2025/2026 at weighted average prices of $69.39 and $68.12 per barrel, gas hedges 80%-85% hedged for 2024-2026.

Risks

• Volatility in crude prices affecting valuation of Wyoming assets.
• Uncertainty in timing of potential transactions for Wyoming assets.
• Impact of development activity on net debt and leverage ratios.

Q: Couple questions on Beta for you. You mentioned in the prepared remarks you guys think you've got a decent batch of pods? You think you can put on the year-end reserve report? I'm curious ballpark numbers. How many locations do you guys think you've derisked with the development you've done so far? And then as we think about medium longer term development plans, how do you guys think about balancing, going for those kind of de risked PUD locations versus maybe stepping out into some newer areas in beta to continue to prove this new strategy out?

A: Hey, Jeff, this is Dan. Kind of hit the last part of your question. The C59 well we drilled as we'll talk more about as we finalize our plans for 2025 and beyond. It really proved up a big chunk of southern part of the acreage that before hasn't really been drilled in this area. And the main part of that was, in the past when Shell drilled these wells, most of these Wells in the 80s technologies didn't really exist to target this part of the reservoir from where the platforms are. So we're very excited about the results we see from this well and specific numbers of locations. We haven't, we're not quite there yet, but we expect in this area decent amount of locations that we'll be talking about. That, was kind of the biggest area to prove up outside this area. You know, the rest of the reservoir is pretty much defined. So I think we got a very good idea of how many locations we'll be able to target and then how many pods we'll be booking this year. Something will work through as well in terms of our timing and what we'll feel comfortable with declaring as pods. So we're excited about that.

Q: Perfect, that's helpful. Thank you. And for my follow up on the cost side, I think on the second well, I think $5.9 million was the number you guys quoted, which is still within that five to six million dollars range you guys initially put out, but obviously a bit above that first well. So just overall wanted to see, I guess if you guys compare contrast, what drove that cost difference and then just bigger picture, your overall comfortability with that $5 million to $6 million range, if that's still a good number?

A: Yes, we feel like that's a good number comparing to the 850 well, for example, which you drilled in the low to mid $4 million range. So the C59 well for example, we had about 8 extra days of drilling. It's mostly driven by, we had to control drill part of the well at a lower rate of penetration because we had very narrow windows, frac gradient, support pressure gradient, just managing through that. And we had to make an extra trip for tool failure while drilling, for example. So yeah, I think if we have no issues and no tool failures while drilling, something similar to 850 well, is it still achievable if we have, these kind of, typical type of issues while drilling, we could be towards the near end of the $5 million to $6 million range we talked about. So we still feel good about our, our estimates going forward.

Q: Yes, thanks. Doing the quick math I guess on the first well seems like it barely declined and if that's a, a fair interpretation and what do you think of like a, an exit rate could be on these wells from IP at the end of a year?

A: Yes, the 850 well, which is typical in this field, in this reservoir, did not see a sharp decline from initial 30 day IP. It's approximately producing about 500 barrels a day now. Exit rate IP on these wells end of the year, it's hard to say, I mean I'll say the characteristics of wells in this field, if you look back historically in their drill, they have obviously higher production. At first you see a little bit of decline. And then if you look at all our wells in the field, this is a normally pressured reservoir that has water flood injection support. So the decline profile of these wells is fairly flat. With that being said, this is one of the first wells we drilled with this type of completion technique as a horizontal well through the desand, we call it the most prolific sand in this field by itself. So exactly how it's going to act in the future, we don't have a great idea. But the results so far are great. And we have high expectations going forward that the decline will be fairly Shallow.

Q: Okay. And did I hear you mention that the second well you encountered high bottom hole pressures and sort of. What do you attribute that to?

A: In the remarks earlier, what I was referring to is the way we're producing the well now is with a high bottom hole pressure compared to a 50 and compared to the other wells producing in the field. That's due to where we set our pump. So all these wells are produced with electric submersible pumps. We set the pump deliberately high in this well because we didn't want to put the pump into a smaller casing closer to the reservoir. The reason for that is all these wells are unconsolidated sands. We complete them with gravel packs, and there's a chance of initial solids and sand production. So we want to keep that pump out of the smaller casing just to avoid any risk of getting that pump stuck if you're producing a lot of sand. So we believe this will be our kind of our mode of operation going forward. These pumps will be set higher, if they need to be, to say, out of the smaller casing. After you produce the wells for a couple months, we'll lower the pump. Lowering that pump down will lower bottom hole pressure. Lowering bottom hole pressure, especially in these reservoirs, we expect to see higher production. So I just made that comment and saying, we saw a very good IP30 on this well, but there's still a lot of drawdown in this well after we lower the pump, which we expect to do before the end of the year.

Q: Okay, thanks. Yes, helpful. And then finally, I guess the monetization opportunities you mentioned in the Haynesville, how do we see how and when do we see that manifest? And maybe some rough contours of what kind of value we're talking about. Without getting into too many specifics?

A: One of the things we've mentioned on prior calls is that our East Texas Haynesville acreage has become more valuable over time. As the play has come towards us, we're looking at different opportunities. Some of them involve creating new amis and maybe selling down some of our position. Others involve just maybe acreage sales. And so we're looking at these different opportunities, and we expect these will be realized fairly soon, probably between say now and kind of the middle of the first quarter kind of timeframe, and the order of magnitudes could be several million dollars to a little bit more than that. So we're looking at different, like I said, different opportunities. And it depends on how we end up structuring the deals. But it is something where we've obviously Never really attributed a lot of value in the past where we think we're bringing, we can bring some of that value forward while also retaining, some optionality to participate in some of these wells moving forward as well. So depending on what level of participation we decide to go forward with, there could be more or less proceeds. And that's why it's a little hard to kind of down a number in the near term. But like I said, I think you'll see more from us between now and call it the middle part of Q1.

Q: Okay, and last question, Martin, on where you are, where you are non op interest owner, can you share any color on what you're seeing with respect to AFES for the next say six to nine months A: Yes. So in East Texas and the Eagle perks. Yes. Obviously we're participating in the wells we mentioned currently that will stretch in the first quarter of next year. And beyond that, we don't have any concrete visibility into what we're going to see in 2025. Oftentimes we see those non operators submitting proposals six to nine months ahead of time. So it is possible we see some more activity in 2025 that we just can't forecast yet.

Q: Thank you. Good morning Dan. Can you remind me how many currently permitted locations you have at Beta?

A: Current permits at beta is 7 to 10, as some of them are being amended right now. So we have permits, we can amend them, but we are currently in the process of permitting more. And just a reminder, we're federal waters, so we don't, we don't permit through the state of California and permits in the past have not been an issue for us at Beta.

Q: Do you need the way you book pod reserves at a field like Beta? Do you need permits in hand to be able to include them into your development plan?

A: No, as long as it's reasonable we'd be able to get them, which today it has been. We don't need those in hand.

Q: Okay, and last question, Martin, on where you are, where you are non op interest owner, can you share any color on what you're seeing with respect to AFES for the next say six to nine months A: Yes. So in East Texas and the Eagle perks. Yes. Obviously we're participating in the wells we mentioned currently that will stretch in the first quarter of next year. And beyond that, we don't have any concrete visibility into what we're going to see in 2025. Oftentimes we see those non operators submitting proposals six to nine months ahead of time. So it is possible we see some more activity in 2025 that we just can't forecast yet.

Q: Okay, and last question, Martin, on where you are, where you are non op interest owner, can you share any color on what you're seeing with respect to AFES for the next say six to nine months A: Yes. So in East Texas and the Eagle perks. Yes. Obviously we're participating in the wells we mentioned currently that will stretch in the first quarter of next year. And beyond that, we don't have any concrete visibility into what we're going to see in 2025. Oftentimes we see those non operators submitting proposals six to nine months ahead of time. So it is possible we see some more activity in 2025 that we just can't forecast yet.