Welcome to Amplify Energy's third quarter, 2024, investor conference call. Amplify's operating and financial results were released yesterday after market close on November 6, 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 the call will be accessible until November 21, 2024, by dialing 800-654-1563 and then entering access code 10171254. I would now like to turn the conference call over to Jim Frew, Senior Vice President and Chief Financial Officer of Amplify Energy Corp. Good morning, and welcome to the Amplify Energy conference call to discuss operating and financial results for the third 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, Martyn Willsher, Amplify's President and Chief Executive Officer, will review our third-quarter performance and provide an update regarding our previously announced strategic initiatives. Next, Dan Furbee, Senior Vice President and Chief Operating Officer, will provide an overview of third-quarter operational performance. Following that, I will discuss third-quarter financial results, provide an update on our balance sheet and liquidity, and provide additional details on our hedge book. Finally, Martyn will conclude our prepared remarks with final thoughts before opening the call up for questions. With that, I will hand it over to Martyn. Thank you, Jim. Amplify continued its strong performance in the third quarter of 2024. The company generated $25.5 million of Adjusted EBITDA and $3.6 million of Free Cash Flow during the quarter, both in line with expectations. As previewed in our last earnings call, we continue to evaluate several proposals regarding the monetization of our Wyoming assets in the third quarter. While we have been encouraged by the interest received in these assets, volatility in crude prices has affected the valuation process with potential buyers. At this time, we believe that retaining ownership of the assets and continuing to benefit from the asset cash flows maximize value for our shareholders. While we are unlikely to transact in the near term, we remain open to a potential transaction if it is in the best interest of shareholders. 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 C-59 well in early October with strong results. With the results of the A-50 and C-59 wells exceeding initial projections and the C-48 expected to come online in mid-November, we intend to include a number of additional development locations into our proved reserves at year-end 2024. We are also refining our development program schedule and expect to have an updated plan with additional details in the first quarter of 2025. Yesterday, Amplify issued its second annual sustainability report, which provides additional disclosures to our stakeholders regarding our business and operating practices. In the report, we discuss the significant progress we have made in the past year, including a substantial reduction in Scope 1 emissions and methane intensity. The report also details our safety procedures, environmental performance, efforts to enhance the long-term sustainability of our business, and dedication to sound corporate governance. I highly encourage our stakeholders to read the report, which can be found under the sustainability section of our website, amplifyenergy.com. We remain committed to continuing to improve our disclosures and to providing updates on our sustainability milestones. In summary, we continue to be excited about our development program at Beta, which has the potential to deliver outstanding returns on investment, significant incremental free cash flow, and materially improve the value of our Beta reserves. Combining this organic development with the additional non-operated investment opportunities in East Texas and Eagle Ford, our continuing focus on LOE optimization initiatives will help realize the full potential of Amplify's 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, Martyn. Total production for the third quarter averaged approximately 19,000 BOE per day, a decrease of 1,300 BOE per day from the second quarter, which benefited from a one-time prior period adjustment of approximately 1,200 BOE per day. Adjusting for this one-time benefit in the second quarter, third-quarter production was approximately flat for the prior quarter despite a scheduled multi-day shut-in at Beta. As discussed earlier in the year, the emissions reduction and electrification project required certain electrical work to be completed, for which production operations needed to be suspended for several days. Our production commodity mix for the quarter was 43% oil, 17% NGLs, and 40% natural gas. For the third quarter, lease operating expenses were approximately $33.3 million, a $3 million decrease from the second quarter. Gathering, processing, and transportation costs were $4.3 million, and production taxes were $6 million. The decrease in lease operating expenses was driven by a $1.2 million reclassification of certain expenses to taxes other than income and our continued LOE optimization initiatives. These operating expenses do not reflect $800,000 of income generated by Magnify Energy Services. Since inception, Amplify has invested approximately $1.5 million in Magnify and generated over $2.9 million in EBITDA. Going forward, we project to generate a run-rate adjusted EBITDA of over $3 million per year after just over one year of operations, and we will continue to explore opportunities to expand Magnify service lines in 2025. The company's total capital investment for the quarter was $18.2 million. Approximately $12 million of this capital was invested at Beta, where we have continued our development drilling program and our electrification and emissions reduction facility project. The remaining capital was invested in non-operated drilling in Eagle Ford and East Texas, as well as various capital workovers and facility projects across our asset base. Capital for the fourth quarter of 2024 is primarily being allocated to the 2024 development drilling program at Beta and the continuation of the non-operated drilling projects. As we noted in our second quarter earnings call, in the Eagle Ford, the company is participating in 14 gross, 0.7 net new development wells and two gross, 0.4 net recompletion projects. In East Texas, the company is participating in four gross, one net wells, with two wells targeting the Haynesville formation and the remaining two wells targeting the Cotton Valley formation. These projects will provide additional volumes and cash flow in early 2025. We are also evaluating opportunities to extract incremental value from our Haynesville acreage through non-operated partnerships and potential monetization opportunities. As for our Beta development program, in the third quarter, we successfully drilled and completed the C-59 well from the Eureka platform and brought it online in early October. The well achieved an IP30 gross oil rate of approximately 590 barrels of oil per day. The C-59 well achieved a third-day IP despite being artificially restricted, as we are currently producing the well with over 1,000 PSI of tubing pressure due to our initial pump setting depth. We intend to lower the pump in the fourth quarter after giving the well sufficient time to freeze any initial solids, which is often expected with gravel-packed completions in the unconsolidated sands. This well was drilled in the far southern area of the Beta field, which is largely undeveloped, and reservoir logs indicated excellent reservoir quality, giving us a high degree of confidence of significant future inventory in this area of the field. In early October, we spotted the C-48 well from the Eureka platform, which we are currently in the process of completing and expect to bring online in the middle of this month. The A-50 well, which was the first well we completed at Beta this year, has been online for approximately five months and has already achieved payout, with cumulative production to date of approximately 85,000 gross barrels of oil, despite the impact of the planned facility shut-ins discussed on this call. With excellent results from the A-50 well drilled from the Ellen platform, strong initial results from the C-59 well, and high expectations for the C-48 well, both drilled from the Eureka platform, we are very excited about the long-term development opportunities at Beta. After the completion of the C-48 well this month, the remainder of 2024 activity at Beta will focus on workover projects, completing the emission reduction and electrification project, and preparing for our 2025 development program. With that, I will turn it over to Jim. Thank you, Dan. I would now like to discuss the following items: third-quarter financial performance, balance sheet and liquidity, and hedging. With respect to third-quarter financial performance, the company reported net income of approximately $22.7 million compared to $7.1 million of net income in the prior quarter. The change was primarily attributable to a non-cash unrealized gain on commodities derivatives in the third quarter compared to an unrealized loss in the prior quarter. As Martyn previously mentioned, third-quarter Adjusted EBITDA was $25.5 million, which was in line with expectations. Third-quarter lease operating expenses were approximately $33.3 million, which were also in line with expectations. LOE was lower than the prior quarter, primarily due to continued optimization initiatives and a reclassification of certain expenses to taxes other than income. Excluding the reclassification, Amplify expects fourth-quarter LOE will be lower than the third quarter and in line with our guidance. With respect to other costs, third-quarter GPT costs were $4.3 million, or $2.45 per BOE, while production taxes were $6 million, or 8.8% of oil and gas revenue. Taxes were higher than the prior quarter due to the previously mentioned reclassification of lease operating expense. The company anticipates that taxes as a percentage of revenue will remain within the previously announced guidance range for 2024. Cash G&A in the third quarter was $6.2 million, or $3.55 per BOE, which was down $0.4 million from the prior quarter. This decrease was in line with expectations and primarily due to lower legal fees. The company anticipates that quarterly cash G&A expenses will remain at approximately the same level in the fourth quarter. In the third quarter, we incurred $3.8 million of interest expense, up $0.2 million compared to the prior quarter. With respect to capital, Amplify invested $18.2 million in the third quarter, which was in line with internal expectations. The company's capital allocation was approximately 66% for Beta facility projects and development drilling, with the remainder distributed across the company's other assets. As Dan mentioned, we are also participating in non-operated development projects in the Eagle Ford and East Texas. Due to the acceleration of non-operated development costs in the fourth quarter, Amplify expects total capital to be at or slightly above the high end of its current annual guidance range of $60-$65 million. Free cash flow, defined as Adjusted EBITDA less CapEx and cash interest expense, was $3.6 million for the third quarter of 2024. Amplify has now generated positive free cash flow in 17 of the last 18 quarters, illustrating the strong, sustainable cash-generating potential of our mature, diversified asset base. On October 25, 2024, Amplify completed the regularly scheduled semi-annual redetermination of its borrowing base. As a result of this redetermination, the borrowing base was reduced $5 million, while elected commitments were increased $10 million, bringing the borrowing base and elected commitments to $145 million. The increase in elected commitments improves the company's liquidity and provides additional flexibility. The next regularly scheduled borrowing base redetermination is expected to occur in the second quarter of 2025. As of September 30, Amplify had $120 million of debt outstanding under its revolving credit facility. Third-quarter net debt increased slightly from the prior quarter due to expected changes in working capital and increased development activity, primarily at Beta. Our leverage ratio improved quarter over quarter to 1.1 times from 1.2 times due to increased last 12 months Adjusted EBITDA. Recently, Amplify took advantage of volatility in the market to add to our hedge position, further protecting future cash flows. Amplify executed crude oil swaps for 2025 and 2026 at weighted average prices of $69.39 and $68.12 per barrel, respectively. Furthermore, the company monetized a small portion of in-the-money gas hedges to stay in compliance with our credit facility. As of November 6, our forecasted PDP crude oil production was approximately 75%-80% hedged for the remainder of 2024 and for full year 2025, with 20%-25% hedged in 2026. On the gas side, our forecasted PDP production is 80%-85% hedged for the remainder of 2024 through full year 2026. We will continue monitoring the market, and we will look for opportunities to add to our strong hedge positions. With that, I'll turn the call back to Martyn. Thank you, Jim. In summary, the first nine months of 2024 have exceeded our expectations, and we continue to be excited about the strong early results from our Beta development program. We remain confident that the combination of our Beta and non-operated development opportunities, coupled with our strong balance sheet and unrelenting efforts to reduce operating costs, have the potential to be transformative for the company, providing a catalyst for market out performance 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. If you would like to ask a question, please press star and one on your telephone keypad now, and you'll be placed into the queue in the order received. If you would like to remove yourself at any time, press pound and one to be removed from the queue. Once again, if you would like to ask a question, please press star and one on your phone now, and our first question comes from Jeff Gramp of Alliance Global Partners. Morning, guys. A couple of questions on Beta for you. You mentioned in the prepared remarks you guys think you've got a decent batch of PUDs 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 de-risked with the development you've done so far? And then as we think about kind of 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? Hey, Jeff, this is Dan. Kind of hit the last part of your question. The C-59 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, technology 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've seen with this well. And specific numbers of locations, we're not quite there yet, but we expect in this area a decent amount of locations, and we'll be talking about that was kind of the biggest area to prove up. Outside of this area, 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 PUDs we'll be booking this year, something we'll work through as well in terms of our timing and what we'll feel comfortable with declaring as PUDs. So we're excited about that. Yeah, and I'll just add, obviously, we only had four PUDs at Beta on our books for this year. We didn't have anything beyond this year booked. And so what we're talking about is adding 2025 to 2029 type development program. And we're always typically a little bit more conservative than most in trying to book PUDs and making sure that we're converting the PUDs over time. But we feel increasingly confident in the return profile of these wells, and that allows us to put things on the books now moving forward that we think will substantially change kind of the outlook for the approved reservoir. Perfect. That's helpful. Thank you. And for my follow-up on the cost side, I think on this second well, I think $5.9 million was the number you guys quoted, which is still within that $5-$6 million 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 and contrast what drove that cost difference, and then just bigger picture, your overall comfortability with that $5-$6 million range, if that's still a good number. Yeah. No, we feel like that's a good number. Comparing to the A-50 well, for example, which you drilled in the low to mid $4 million range, so the C-59 well, for example, we had about eight 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, fracture gradient to pore pressure gradient, just managing through that. And we had to make an extra trip for a tool failure while drilling, for example. So yeah, I think if we have no issues and no tool failures while drilling, something similar to the A-50 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-$6 million range we talked about. So we still feel good about our estimates going forward. Perfect. Always coming off top on. Yeah, this is the first well we've drilled up Eureka. So just kind of managing the drilling in a different area off a different platform with a different rig, we were trying to kind of make sure that we were managing the drilling in a conservative manner as we went through. So hopefully they can move up or move down, so to speak, but we're comfortable in that $5-$6 million range going forward, and hopefully we can continue to improve. Understood. Good details. Thank you, guys. Our next question comes from Subhash Chandra of Benchmark. Yeah, thanks. Doing the quick math, I guess, on the first well, it seems like it barely declined. And if that's a fair interpretation, what do you think of an exit rate could be on these wells from IP at the end of the year? Yeah, the A-50 Well, which is typical in this field and this reservoir, did not see a sharp decline from its initial 30-day IP. It's approximately producing about 500 barrels a day now. Exit rate IP on these wells at the 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 and they're drilled, 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 D sand. 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. 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? 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 sand. 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 kind of our mode of operation going forward. These pumps will be set higher if they need to be to stay out of the smaller casing. After you produce the wells for a couple of months, we'll lower the pump down. Lowering that pump down will lower the bottom hole pressure. Lowering bottom hole pressure, especially in these reservoirs, we expect to see higher production, so I just made that comment in 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. Okay. Thanks. Yeah, it's 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, 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 time frame. And the order of the magnitudes could be several million dollars to a little bit more than that. So we're looking at, 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 can bring some of that value forward while also retaining some optionality to participate in some of these wells, although albeit at a non-operated level of interest, similar to how we've structured other deals in the past in the East Texas area. Okay. Thanks. And one more, and I'll hop off if I can. When do you envision a return of capital? I think you have to get below, say, $90 million or so on the bank utilization. But do you think of that being the trigger, or would you want to be more delevered? It's a great question. I think with the increase in actually, with the increase in kind of the credit facility elective commitments, that number has gone from, call it $90 million up to around $100 million to where you're below that threshold. So certainly something that we hope to be looking at in 2025. I'm not going to put in an exact date on it yet, but it also depends on development activity and how fast we drill and develop Beta. So there's a little bit of a moving target there depending on how are we going to increase the level of activity at Beta. And if so, that might delay in a quarter or so. So we're looking at that. That's kind of part of the plan, and part of why we're kind of looking at budget for next year and kind of really making sure that we're comfortable with the timing assumptions on the capital spending and how it impacts free cash flow and the ability to return capital at some point in 2025. Great. Thank you all. Our next question comes from Jeff Robertson of Water Tower Research. Thank you. Good morning. Dan, can you remind me how many currently permitted locations you have at Beta? Current permits at Beta is seven 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 in federal waters, so we don't permit through the state of California. And permits in the past have not been an issue for us at Beta. Do you need the way you book PUD reserves at a field like Beta? Do you need permits in hand to be able to include them into your development plan? No. As long as it's reasonable, we'd be able to give them, which to date it has been. We don't need those in hand. Yeah. I think part of what we're doing between now and, call it, the early part of next year is, one, we're going to increase the number of permits that we do have in hand. Obviously, we're mapping out a number of additional locations through different areas of the field, taking advantage of the fact that we now have refined our lowest known oil in the southern part of the Eureka acreage, looking at the different wells that we're going to be kicking off from and putting in drilling plans, reflecting those. And so we're using this time to, once again, set up the 2025 plan, but also the plan beyond 2025, and looking at the specific well bores that we'll be using, whether we're drilling some from the conductor or if we're going to just drill all of them from existing well bores. And so we have enough permits for next year, but we're going to, like I said, we might high-grade new ones based on if we like a certain location helps kind of the program. And we're also more likely than not to stay on Eureka for the early part of next year as well, given that we are given the success we're seeing in some of the opportunities. So all of those things are being kind of worked through as we get through the end of this year and into the beginning of next year so that we can set up the most successful 2025 program that we can create. Thanks. And just to follow up on East Texas, did I hear right that the monetization is mostly currently non-producing acreage that you might still retain in some sort of a non-op type interest in? Yeah. So most of this is acreage that's held by production in the Cotton Valley Formation, but we also have the deep rights. So it's not something that you would see any value for in our reserve report, for example. We wouldn't have drilling locations on this acreage. And so it's a combination of, once again, some monetization where we bring cash forward, but also the potential to allow ourselves 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 pin 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. Okay. And last question, Martyn, on where you are a 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? Yeah, so in East Texas and the Eagle Ford, yes, obviously, we're participating in the wells we mentioned currently that will stretch into 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. Okay. 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. I'd just like to express my appreciation to all of our employees for their outstanding efforts and dedication this year, as well as the continued support of all of our stakeholders. Thank you for participating in the call today. As always, if you have any follow-up questions, please don't hesitate to reach out directly. Thank you. Thank you. This does conclude today's Amplify Energy Q3 2024 earnings conference call. Thank you for your participation. You may disconnect at any time.