Amplify Energy Corp.

Welcome to Amplify Energy's second quarter 2024 investor conference call. Amplify's operating and financial results were released yesterday after market close on August 7th of 2024 and are available on Amplify's website at www.amplifyenergy.com. During this conference call, all participants will be in a listen-only mode. Today's call is being recorded. A replay of this call will be accessible until August 22, 2024, by dialing 800-654-1563 and then entering access code 717-24901. I would now like to turn the conference call over to Jim Frew, Senior Vice President and Chief Financial Officer of Amplify Energy Corp. Please go ahead.

Good morning, and welcome to the Amplify Energy Conference Call to discuss operating and financial results for the second quarter of 2024. Before we get started, we would like to remind you that some of our remarks may contain forward-looking statements which reflect management's current views of future events and are subject to various risks, uncertainties, expectations, and assumptions. Although management believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurances that such expectations will prove to be correct and undertakes no obligation and does not intend to update these forward-looking statements to reflect events or circumstances occurring after this earnings call. Please refer to our press release and SEC filings for a list of factors that may cause actual results to differ materially from those in the forward-looking statements made during this call. In addition, the unaudited financial information that will be highlighted here is derived from our internal financial books, records, and reports. For additional detailed disclosure, we encourage you to read our Form 10-Q, which was filed yesterday afternoon. Also, non-GAAP financial measures may be disclosed during this call. Reconciliations of those measures to comparable GAAP measures may be found in our earnings release or on our website at www.amplifyenergy.com. During the call, Martin Wilshire, Amplify's President and Chief Executive Officer, will review our second quarter performance and provide an update regarding our previously announced strategic initiatives. Next, Dan Furby, Senior Vice President and Chief Operating Officer, will provide an overview of second quarter operational performance. Following that, I will discuss second quarter financial results, provide an update on our balance sheet and liquidity, and provide additional details on our hedge book. Finally, Martin will conclude our prepared remarks with final thoughts before opening the call up for questions. With that, I will hand it over to Martin.

Thank you, Jim. Amplify had a strong second quarter of 2024. The company generated $30.7 million of adjusted EBITDA and $9.2 million of free cash flow during the quarter with both exceeding expectations. Due to our stronger than expected second quarter performance, combined with the company's election to participate in high return non-operated development wells in East Texas and Eagleford, we have revised our annual guidance. You can find our updated guidance on our earnings release and investor presentation posted to our website last night. With respect to the strategic initiatives highlighted on our previous calls, we received multiple bids for both an outright sale and partial monetization of our barrel assets following a comprehensive marketing process. The company, working with its advisors, continues to actively evaluate these proposals and will provide updates as they become available. The company is committed to pursuing the path it believes will maximize shareholder value. At Beta, we continue to make progress in our 2024 development program. Dan will provide more details in a moment, but we are pleased to announce that we successfully drilled and brought online the A50 well in early June with very strong results. The cumulative production received to date from this well continues to exceed the upper band of our expectations, which were based on a limited subset of analogous wells previously drilled off the Beta platforms. With the results of the A50 and comparable results from future development wells, we would anticipate increasing our expectations for undeveloped well productivity. In addition, it is important to note that our current SEC approved reserves of beta only include the four wells we plan to drill in 2024. With continued success, we have a substantial number of additional development locations that we may add to our approved reserve inventory. The combination of increased productivity forecasts and additional locations has the potential to materially impact the value of our beta reserves and demonstrate the strategic value of this prolific asset. In summary, we continue to focus on optimizing future cash flow generation by pursuing our strategic initiatives at Barrel and Beta and capitalizing on incremental non-operated investment opportunities in East Texas and Eagleford. We believe the strategy will unlock the full potential of amplified diverse portfolio of assets and deliver substantial benefits and long-term value to our shareholders. With that, I will hand it over to Dan.

Thank you, Martin. Total production for the second quarter averaged approximately 20,300 BOE per day. Second quarter production benefited from a one-time prior period adjustment of approximately 1,200 BOE per day, which was partially offset by production curtailments in East Texas related to significant flooding events. For over 100 days, the high level of the Sabine River impeded access to a significant number of wells in East Texas, forcing shut-ins across the asset base. The team did an excellent job of minimizing the impact of this flooding, and conditions have significantly improved as of this month. Excluding the impact from the prior period adjustment, our production commodity mix for the quarter was 41% oil, 19% NGLs, and 40% natural gas. For the second quarter, lease operating expenses were approximately $36.3 million, a $2 million decrease from the first quarter. Gathering, processing, and transportation costs were $4.9 million. and production taxes were $4.6 million. The decrease in lease operating expenses is partly related to annual maintenance expenses taking place in the first quarter, as well as continued cost reduction efforts from the team, which are expected to persist for the remainder of the year. These efforts include previously discussed initiatives with Magnify Energy Services, our wholly owned subsidiary. Magnify generated approximately $900,000 of adjusted EBITDA in the quarter through compression rentals, vacuum truck services, slick line work, and well testing services. Since inception, Amplify has invested approximately $1.5 million in Magnify, which is projected to generate a run rate adjusted EBITDA of over $3 million per year after only one year of operation. We will continue to explore additional services for Magnify in the coming quarters. The company's total capital investment for the quarter was $18 million. Approximately $16 million of this capital was invested at Beta, where we continue our electrification and emission reduction facility project and our development drilling program. The remaining capital was invested in various capital workovers and facility projects across our asset base. Capital for the second half of 2024 will primarily be allocated to continued development and facility enhancements at Beta and non-operated drilling projects in the Eagleford and East Texas. In the Eagleford, the company expects to participate in 14 gross .7 net new development wells and two gross .4 net re-completion projects. In East Texas, the company expects to participate in four gross one net wells with two wells targeting the Hainesville Formation and the remaining two wells targeting the Cotton Valley Formation. These projects will provide additional volumes and cash flow in early 2025. The two new development wells in the Hainesville Shale represent a new opportunity for Amplify. As development of the Hainesville has continued to move west, and activity has increased near our anchorage position. With the incremental optionality provided by the Hainesville opportunities, we believe that we will be in a strong position to extract additional value from this area in the future. At Beta, we continue the third and final phase of the electrification and emission reduction project involving the installation of selective catalytic reducers on the platform generators and rig engines. We are on schedule to complete this multi-year project in the fourth quarter of this year, which will lower operating expenses by reducing diesel usage and emission credit purchases, increase redundancy across our operations, and bring us in line with regional air quality standards. We are projected to invest $14 million towards this project this year, and once completed, we do not anticipate significant facility capital investments at BEVA in the coming years. With the fixed cost improvements from these upgrades and the use of modern technologies in our drilling program, we believe we can recover the massive remaining reserves in the beta field. As for the development program, we successfully drilled and completed the A50 well from the Ellen platform in less than 30 days and brought it online in early June. The well achieved a gross peak IP30 oil rate of approximately 730 barrels of oil per day, Rates from the well after approximately two months of production were in excess of 650 barrels of oil per day. These early production results exceed the high end of the cumulative production range presented in our investor deck. We invested approximately $4.2 million in this well, and at current oil prices, we project a quick payback of approximately four months. The excellent results of this well reinforce the substantial upside that can be achieved through a successful development campaign utilizing modern technology to drill extended reach laterals to parts of the beta field that were not accessible in previous drilling programs. In the third quarter, we are drilling the C59 well from the Eureka platform and then intend to drill a second well in Eureka before returning to Ellen, likely late in the fourth quarter, to finish the A45 well, which was deferred earlier this year. And with that, I will turn it over to Jim.

Thank you, Dan. I would now like to discuss the following items, second quarter financial performance, balance sheet and liquidity, and hedging. With respect to second quarter financial performance, the company reported net income of approximately $7.1 million compared to a $9.4 million net loss in the prior quarter. The change was primarily attributable to lower non-cash unrealized losses on commodity derivatives in the quarter. As Martin previously mentioned, second quarter adjusted EBITDA was $30.7 million, which was well above expectations. In addition to the strong operating performance outlined by Dan, Amplify benefited from a one-time prior period accounting adjustment. In the first half of the year, the company undertook a comprehensive review of its suspense accounts. Based on the results of our research, we determined that a portion of our suspense balance should be released and credited to Amplify. The net impact of these adjustments positively impacted adjusted EBITDA by approximately $7 million in the second quarter. Second quarter lease operating expenses were approximately $36.3 million, which was in line with expectations. LOE was lower than the prior quarter, primarily due to one-time costs that impacted the prior quarter. Amplify expects second half LOE will be lower than the first half, with full year LOE remaining within the original guidance range. With respect to other costs, second quarter GPT costs were $4.9 million, or $2.66 per BOE, while production taxes were $4.6 million, or 6.4% of oil and gas revenue. Due to low gas prices in 2024, We expect ad valorem taxes will be lower for the remainder of the year, and we have updated guidance to reflect that change. Cash G&A in the second quarter was $6.6 million, or $3.57 per BOE, which was down $1.3 million from the prior quarter. This decrease was in line with expectations and primarily due to year-end processes that increased costs in the first quarter. the company anticipates that quarterly cash G&A expenses will be relatively flat through the remainder of the year, and as a result, we have not adjusted our original G&A guidance range. In the second quarter, we incurred $3.6 million of interest expense, up $.1 million compared to the prior quarter. With respect to capital, Amplify invested $18 million in the second quarter, which was in line with internal expectations. As Dan mentioned, we have now elected to participate in non-operated development projects totaling $7 to $9 million in the Eagle Ford in East Texas and have updated our guidance accordingly. We now expect to invest $60 to $65 million of capital in 2024. Free cash flow defined as adjusted EBITDA, less CapEx and cash interest expense was $9.2 million for the second quarter of 2024. Amplify has now generated positive free cash flow in 16 of the last 17 quarters, illustrating the strong, sustainable cash-generating potential of our mature, diversified asset base. As of June 30th, Amplify had net debt of approximately $117.5 million, consisting of $118 million outstanding under our evolving credit facility and $.5 million of cash and cash equivalents. At the end of the second quarter, the company's liquidity was $17.5 million, and net debt to last 12 months adjusted EBITDA was 1.2 times. The slight increase in net debt versus the prior quarter was primarily due to expected changes in working capital and increased investment activity, primarily at beta. The next redetermination of our borrowing base is expected in the fourth quarter of 2024. As of August 7th, Our forecasted approved developed producing crude oil production was approximately 70 to 75% hedged for the second half of 2024, 55 to 60% hedged for 2025, and 10 to 15% hedged in 2026. On the gas side, our forecasted PDP production is 85 to 90% hedged for the remainder of 2024 and for full year 2025, with 80 to 85% hedged in 2026. In the second quarter, we added gas hedges covering a portion of our expected 2026 production and crude hedges covering a portion of our 2025 expected production. Amplify executed 2026 natural gas swaps at a weighted average price of $3.88 per MMBTU and natural gas collars with a floor of $3.62 per MMBTU and a ceiling of $4.27 per MMBTU. Amplify also executed crude oil shops for 2025 at a weighted average price of $74.10 per barrel. We will continue monitoring the market to supplement our strong hedge positions going forward. And with that, I'll turn the call back to Martin.

Thank you, Jim. As I mentioned earlier on this call, we are updating guidance based on our strong first half results and the company's election to participate in non-operated development wells in East Texas and Eagleford. Amplify's updated guidance is based on four-year 2024 commodity prices for WTI crude oil of $76 a barrel and Henry Hub natural gas of $2.25 per mbtu. As previously disclosed, the company expects to invest 85% to 95% of its capital in the first three quarters of the year, primarily in connection with the beta projects. Additional guidance details are provided in our earnings release and can be found in the latest investor presentation currently available on our website. In summary, the first half of 2024 has exceeded expectations, and we are excited about the initial results of our development program at Beta. The successful development program at Beta is key to demonstrating the strategic potential of the asset and has the potential to materially increase cash flows and long-term value for the company. We remain confident that the combination of our exciting Beta and non-operated development opportunities, coupled with our strong balance sheet and relentless focus on cost structure, have the potential to be transformative for the company, providing a catalyst for market outperformance while also enhancing our flexibility as we consider and evaluate potential capital return options in future periods. With that, operator, we are now open for questions.

Thank you. If you would like to ask a question at this time, please press star 1 on your telephone keypad. You may remove yourself at any time by pressing star 2. Once again, to ask a question, please press star 1. And we will take our first question from Jeff Gramp with Alliance Global Partners.

Good morning, guys, and congrats on getting the beta news out. I wanted to unsurprisingly start there. So I think when you guys originally announced this development program, it included the four wells for this year, as you guys have talked about. And I think the plan was, I think, three wells in 2025. Given the results so far, I know we still have a few more wells to continue to de-risk this, but what are the constraints to doing more than those three wells in 25? Or how do you guys just generally think about a potential acceleration case there?

Yeah, I think that's something that we're going to take a closer look at through the second half of this year, especially as we continue to get additional results. Obviously, we can drill and complete these in approximately 30 days. So we do mix in workovers using the same rigs during the course of the year, and we obviously always want to keep an eye on total capital, but we do have the flexibility to adjust that a little bit as we go forward, and that's something that we'll look at, like I said, as we continue to get additional results here in the third and fourth quarter.

Okay, understood. And then on the well cost front, I think you guys were originally targeting kind of five to six million. This one came in in kind of the low fours. What's your assessment of the repeatability of that? I mean, if anything, I would think, you know, the earlier wells would be on the more expensive side as you guys kind of ramp up efficiencies and learnings and things of that nature. What's kind of the confidence level to continue to come in under that initial five to six range?

Hey, Jeff, this is Dan. The $5 million to $6 million estimate, so we made that obviously before we started drilling wells out here. The team did a great job on the 850. We're very efficient, got the well done on time. And we'll see as we go. We're going to get a few more wells under our belt before we lower our overall expectation, but it's certainly possible to drill these wells for less than $5 million.

Okay, great. And then if I could sneak one more in, the new non-op wells that you guys elected to participate in that popped up in East Texas, obviously gas prices are not tremendously high right now, but I assume they kind of met your hurdle rate. But just kind of wondering what your assessment is. Is this kind of setting up a potential longer-term capital allocation potential in East Texas, or is this just a couple – maybe one-offs where you guys just kind of wanted to participate and kind of get a look for what these well economics could be down the road.

So I think it's a combination of both, but, you know, I'll say that, you know, the Hainesville has been, you know, obviously perspective in our area, but the activity keeps getting closer and closer now is obviously on our acreage. And we have a meaningful amount of Hainesville acreage that is now perspective and And obviously we want to, you know, learn firsthand, especially as we look to decide what to do with, we have some contiguous acres where you could have an entirely different drilling program and, you know, whether we want to partner up or do something different with some of those acres. And so this is an opportunity to learn more while participating in a kind of a lower risk kind of 25% working interest level. But we do have some interesting opportunities now in Hainesville. And obviously, yes, gas prices are low. They're forecasted to be better next year. But even with where they're currently projected, we feel comfortable with the returns. And like I said, we like understanding what our optionality is going to be down the road in this area, which is, like I said, an area which could increase in importance to us for 25 and beyond. Okay. Sounds good. Thank you guys for the time. Thank you, Jeff.

Thank you. And our next question comes from John White with Roth Capital.

Good morning and congratulations on a strong quarter and getting your bids in on the bear oil property. You mentioned several times maximizing shareholder value. Assuming a closing and a robust amount of sale proceeds from barrel, do you have a preference at this time for capital returns? Would it be instituting a stock buyback or initiating a stock dividend program?

Yeah, so let me kind of take both parts of that. So obviously when you're in an active discussion, we have to be very careful about what information we disclose. And so I'm sure while we'd love to kind of say more, we have the option to sell it outright, the option to potentially monetize it partially, or the option to just hold it if we think that's what's best for the company longer term. So that's all in, like I said, that's a process that's currently ongoing. still very active and we can only provide the updates once they're more definitive. At the same time, in terms of capital returns, I always say that this is going to be dependent on what we see at the time. In the past, we've done both dividends and stock buybacks. Both of those are certainly on the table. It could be one or the other. It could be a combination of both. you know, whether we accelerate that by monetizing in some way, barrel, or whether we do it through, you know, cashflow generation, which will pick up considerably in key form beyond, um, where we'll evaluate both of those options, um, at the appropriate time. But at this point be inappropriate for me to basically speculate on what the board will decide to do.

Um, at that time, I understand your constraints in, uh, your communication. And thanks for addressing it. I'll turn the call back. Thank you, John.

Thank you. And we will take our next question from Subhash Chandra with Benchmark.

Yeah, thanks. Yeah, congrats too on finally, you know, showing the value of beta. Were the cycle times pretty much what you expected on the A50 or was it faster?

It's about what's expected. Drilling complete time, we expect less than a month. Every well out here is a little different. Some will take a little longer than this one did. Some will take a little shorter. But every well we currently are looking at in our inventory should be less than a month if the drilling takes place as we expect it to.

Got it. Okay. So, you know, I think back to maybe a question that Jeff had asked, you know, so I guess with the Haynesville play, you want to take a look and maybe this is a cost effective way of taking a look at what the value of the acreage is. Or it could have been, you know, arguably two more, you know, California wells, right? So how did that sort of, you know, value proposition, how do you sort of walk through that?

Yeah, I don't think our ultimate constraint on California is going to be the capital. I think, obviously, with the quick payback of these wells, we have the ability to ramp up if it makes sense to do so. And so that's something that, like I said, we'll obviously be cognizant of capital allocation. But with the free cash flow we're generating, like I said, more so starting in the fourth quarter, I think we'll have optionality there to both participate in the Hainesville, if that makes sense, but also if we decide to go a little faster and increase activity in California, we can do that as well. So I don't think one precludes the other. It's, you know, you've got to kind of take advantage of opportunities as they come up. And so we're also full speed ahead right now and obviously on beta with the next two wells coming up right after, you know, in this quarter and should be online before our next call. Okay, yeah.

No, that makes sense. I mean, you know, I guess the acceleration, let's say a significant acceleration, would that be, because you have a lot of free cash flow coming for sure, but then you have these monetization events that are, you know, potential. Do we need both to sort of see a material acceleration in California and understanding that you're walking through the, you know, the results of the wells, but let's say they all come out looking like 850s. Do you need both to occur, or do you think you can materially accelerate just through organic free cash flows?

I think we can clearly, or, you know, even if you doubled activity levels in 2025, just as an example, I think we have more than sufficient organic free cash flow to do that. You know, the infrastructure project at Beta has obviously... up a lot of that free cash through and will continue to through the third quarter, which is where we've talked about how the fourth quarter is really where we'll start to generate more of a go-forward free cash flow look. But that is also impactful from a full fixed cost perspective on that platform. So it will also, once again, kind of increase the cash flow off the beta assets, not just from the development side, but also reducing the cost side going forward. And so it's much more meaningful in the fourth quarter and beyond, like I said. So I don't think it's impeding us. It's not going to be the constraint to a faster program if that's what we choose to do.

got it yeah so it's that operating leverage that we really should begin to see in the fourth quarter with uh with the four wells on yeah i guess that wasn't a question all right thanks guys thank you thank you thank you and we will take our next question from jeff robertson with water tower research

Thank you. Martin, following up on where you ended that, can you talk at all or can you provide some color on where you think LOE in beta will go with the electrification and the additional volumes?

Yeah. Hi. This is Dan. LOE in beta, yeah. As we finish this project, and this project's doing several things, it's redundancy, it will lower LOE, and it's required by the air quality standards by the South Coast Air Quality District in Southern California. But, you know, what this will do for us, it will reduce essentially all of our diesel usage in California from an operating standpoint, and it should reduce overall power costs. And a big part of our LOE right now is, in addition to diesel with beta, we have to buy NOx credits. emission credits to offset our NOx emissions. After this project, NOx emissions will be almost nonexistent, so we'll save those costs as well. So we expect next year to see a sizable reduction in total beta LOE once this project is fully completed.

I think, Dan, in the second quarter, LOE and beta was just short of $43 per BOE. Do you know where that could go? I think you were at $34 a BOE in the fourth quarter of 24, I'm sorry, 23.

Yeah, and quarter by quarter, it's going to jump around some as part of our LOE as well is work over expenses. So in addition to drilling wells, our rig crews out there, we have to pull ESPs different times and they fail throughout the year. So depending if we're doing expense work overs or drilling wells within a certain quarter, that will move that LOE number up and down. But we'll have more information as we get further in the year as to what our LOEs are going to look like on a total absolute basis of beta and on a unit basis like you're talking about here for next year of what we expect to be trending now.

Jeff, the other thing I would add to that, this is Jim, is as we ramp up volumes, you're talking per BOE, right? So as we ramp volumes with the drilling program, our costs are generally fixed out here. So our per BOE costs are going to come down as we increase our volumes. So again, we'll have more on this coming forward, but I think that the story is generally a positive one.

Right. Costs come down and margins go up. That's right. Jim, on the RBL's redetermination in the fall, I think before ADA went offline, the borrowing base was $225 to $240 million. Right. With the barrel oil sale and having beta on in the development, can you give any color on where you think an RBL might be after the redetermination and what that will do just for the liquidity on paper?

So like Martin said, right, I think it's a little bit early to speculate in terms of the barrel monetization and what that may do. So it makes it a little difficult to answer your question. That being said, right, we – are generating free cash flow, so there's not a huge need for us to increase the size of a facility today, I think. But again, as we add reserves and as we add value, we will have the option to do that, assuming our lenders are supportive. So from our perspective, it's not a major concern right now. And again, kind of similar to what I just said, more upside than not as we continue to do things at beta.

Yeah, I'll just add that, you know, the barrel – facility does not meaningfully impact the credit facility so and our borrowing base is higher than our committed capital um so you know there's selling it wouldn't have a huge impact on the availability of of the you know the credit facility and obviously so whatever you sold it for monetized it for would obviously be incremental um liquidity um once again you know we're given the nature and status of our discussions, we're not alluding to whether or not we're going to transact on it or not at this point. We just want to make sure that we're, like I said, open to all opportunities. Thanks, Martin.

Thank you. It appears that we have no further questions at this time. I will now turn the program back to our presenters for closing remarks.

Thank you. With that, I'd just like to say thank you to all of our employees for their outstanding efforts and dedication this year. And I'd also like to express my appreciation to all of our stakeholders for their continuing support. We appreciate you all participating in our call today. And as always, if you have any other follow-up questions, please don't hesitate to reach out directly to us. Thank you, everyone.

Thank you. This does conclude today's Amplify Energy second quarter 2024 investor conference call. Thank you for your participation. You may disconnect at any time.