Amplify Energy - Earnings Call - Q4 2024

Executive Summary

• Q4 2024 was operationally mixed: production slipped to 18.5 Mboe/d and Adjusted EBITDA declined to $21.8M on lower realized oil prices and unplanned Beta ESP failures, while free cash flow remained positive for the 10th straight quarter and management reiterated a 2025 ramp at Beta and accretive Juniper transaction closing in Q2 2025.
• Reported net loss of $7.4M (-$0.19/sh) was driven by non-cash unrealized losses on commodity derivatives; Adjusted Net Income was $5.1M, highlighting resilient underlying operations despite transient issues.
• 2025 standalone guidance targets 19–21 Mboe/d and $100–$120M Adjusted EBITDA with $70–$80M capex, underpinned by six Beta completions; management cites IRRs ~100% for Beta wells and early 2025 Beta oil rates up ~9% vs Q4.
• Catalysts: (1) C48 well (first C-sand horizontal) early performance readouts, (2) Juniper deal approval/close and financing, (3) 2025 Beta cadence and Bairoil power cost savings (~$0.5M/month in 2H25), and (4) hedge-protected cash flows (oil 70–75% and gas 85–90% 2025 PDP hedged).

What Went Well and What Went Wrong

• What Went Well

  • Beta development momentum: A50 and C59 outperformed type curves with IRRs >100%; six 2025 completions planned, and early March Beta oil rates +~9% vs Q4 with C48 drawdown ongoing.
  • Strategic portfolio moves: East Texas Haynesville monetizations generated ~$7.6M net proceeds while retaining upside (10% WI/ORRI, AMI with >30 gross locations).
  • Balance sheet and hedging: Net debt/LTM Adjusted EBITDA 1.2x with $127M RCF drawn; oil 70–75% and gas 85–90% of 2025 PDP hedged; 2025–2026 additional oil swaps at ~$68/Bbl.

• What Went Wrong

  • Q4 EBITDA and production softness: Adjusted EBITDA fell to $21.8M (from $25.5M in Q3) and production to 18.5 Mboe/d, driven by lower realized oil prices and Beta ESP failures/workovers (LOE +5% q/q).
  • Non-cash derivative headwind: Unrealized loss on commodity derivatives swung to a loss, driving GAAP net loss of $7.4M (vs Q3 $22.7M profit).
  • Cost pressure at Bairoil: Higher regulated electricity rates contributed to lower PV-10 and are a headwind, though mitigation projects are planned for 2H25.

Transcript

Dan Furbee (SVP and COO)

Welcome to Amplify Energy's fourth quarter 2024 investor conference call. Amplify's operating and financial results were released yesterday after market close on March 5th, 2025, 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 March 20th, 2025, by dialing 800-654-1563 and then entering access code 71724906. A transcript and a recorded replay of the call will also be available on our website after the call. I would now like to turn the conference over to Jim Frew, Senior Vice President and Chief Financial Officer of Amplify Energy.

James Frew (SVP and CFO)

Good morning, and welcome to the Amplify Energy conference call to discuss operating and financial results for the fourth 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-K, which was filed yesterday afternoon, and our definitive proxy statement regarding the Juniper acquisition, which was filed on March 4th, 2025. 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 provide an update regarding our strategic initiatives, including our announced transaction with Juniper, two recent deals in East Texas, and an overview of our activities at Beta. Next, Dan Furbee, Senior Vice President and Chief Operating Officer, will provide an overview of fourth quarter operational performance and provide a preview of 2025 activities.

Following that, I will discuss fourth quarter financial results, provide an update on our balance sheet and liquidity, and provide additional details on our hedge book. Finally, Martin will provide final thoughts before opening the call up for questions. With that, I will hand it over to Martin.

Martyn Willsher (President and CEO)

Thank you, Jim. I'd like to start with an update on our recently announced transaction with certain portfolio companies of Juniper Capital, discuss our recent Haynesville transactions in East Texas, and provide an update on our key development activity at Beta. On January 15th, 2025, Amplify announced it had entered into a definitive merger agreement with privately held Juniper Capital to combine with certain of its portfolio companies owning oil-weighted assets and leasehold interests in the DJ and Powder River Basins. We are extremely excited about this deal and believe it is an important step in our strategic development. The deal provides numerous benefits to the organization by increasing our scale and operating margins, expanding our inventory of attractive drilling locations, and providing us with a new core area for potential M&A activity.

In regards to scale and upside, using flat pricing of $70 per barrel for oil and $3.50 for natural gas, year-end 2024 proved developed reserves for these assets are 18 million barrels of oil equivalent with a PV10 value of approximately $335 million, and total proved reserves are 50 million barrels of oil equivalent with a combined PV10 value of $614 million. Amplify believes there is additional upside potential on the expansive acreage position, which is comprised of approximately 287,000 net acres and adjacent to some of the largest publicly traded U.S. oil companies. The Juniper transaction is also expected to provide substantial synergies from an overhead and tax perspective, with an expected G&A increase of approximately $1 million versus $7-8 million for the existing portfolio companies and tax synergies from the stepped-up tax basis of the acquired companies.

With the combined impact of the asset cash flows and deal synergies, we expect the transaction to increase significantly accreted to free cash flow in 2025 and over a five-year time horizon. The large acreage position and operating footprint in these premier Rocky Mountain Basins also provide the company with a new core area for future consolidation opportunities, with the potential for accretive bolt-on acquisitions from smaller private companies or non-core assets of large operators. Additionally, the more broadly scaled pro forma asset base will afford Amplify flexibility to consider portfolio rationalization opportunities to improve operational focus and manage cash flow. Finally, the transaction has the added benefit of bringing on a new long-term partner in Juniper Capital, who has demonstrated a strong track record of delivering substantial value to their stakeholders. We anticipate the Juniper transaction will close in the second quarter of 2025.

In addition to the Juniper transaction, the Amplify team has recently closed on two separate transactions in East Texas, allowing the company to bring forward value associated with our Haynesville acreage. Between the two transactions, Amplify generated $7.6 million in net proceeds while retaining an overriding royalty interest in the properties with a 10% non-operated working interest in future development. We believe the acreage conveyed has over 30 undeveloped Haynesville locations with compelling economics. Although smaller in scope, these deals demonstrate management's commitment to creatively realizing value associated with our more mature assets. At Beta, we intend to build off the successes of the 2024 development program. The first two wells we brought online, the A50 and the C59, continue to perform above our pre-drill type curves with IRRs in excess of 100%.

Based on this success, we were able to add 23 additional PUD locations to our year-end reserves with a PV10 value of approximately $180 million at a $70 flat WTI price for oil. In 2025, we plan to complete six additional Beta wells, which includes the C48 and the A45 that were deferred from the 2024 program. While we are currently planning for five wells per year in 2026 and beyond, with continued success from the 2025 program, we will have the flexibility to accelerate drilling in future years to capture incremental value from this enormous resource. In summary, our accomplishments in 2024 have provided a strong foundation for the future success of Amplify, and we intend to build up that success with our strategic initiatives in 2025.

The completion of the Juniper transaction will provide substantial upside in scale to the organization and complement the outstanding development potential of the Beta asset. We also intend to remain focused on maximizing the value of our existing asset base through accretive capital projects, cost reduction efforts, and the evaluation of portfolio optimization opportunities. With that, I will hand it over to Dan.

Dan Furbee (SVP and COO)

Thank you, Martin. During the fourth quarter of 2024, average daily production was approximately 18.5 MBOE per day, a decrease of 0.5 MBOE per day from the prior quarter. Production was impacted primarily by gas volumes, mostly in East Texas, due to purchaser interruptions and residue gas realizations after processing, which resulted in higher NGL realizations as a percentage of our total production. Oil volumes were incrementally higher from the previous quarter, despite platform shutdowns at Beta early in the quarter following the completion of the emission reduction and electrification facility projects, and 10 ESP failures in the fourth quarter at Beta, which significantly impacted our base production.

The multi-year electrification and emissions reduction project has now been completed, and all of the failed wells have had ESPs replaced by the end of January 2025, and we are projecting Beta production to be significantly higher than the fourth quarter for the impact of the 2025 drilling program. As of March 2, 2025, our current seven-day average production rate at Beta was 4,834 gross or 3,635 net barrels of oil per day, with minimal contribution from the recently completed C48 well, which we continue to draw down since completing it in February. Our current production rates at Beta represent an approximate 9% increase from fourth quarter 2024 volumes. Our production commodity mix for the quarter was 45% oil, 17% NGL, and 38% natural gas. Looking forward to 2025, our production guidance range is 19,000-21,000 barrels of oil equivalent per day.

The midpoint of our oil production guidance represents a 7% increase from 2024 oil production driven by our development at Beta, which is projected to more than offset the natural oil decline of our Beta asset. For the fourth quarter, lease operating expenses were approximately $35.1 million, a $1.8 million increase from the prior quarter. The 5% increase in LOE from the prior quarter was mostly driven by the additional unplanned workovers at Beta due to the failed ESPs. With those wells now back online, Amplify expects those costs to normalize. Lease operating expenses for the fourth quarter also do not reflect $900,000 of income generated by Magnify Energy Services.

We expect to continue improving our cost structure throughout 2025 and are guiding lease operating expenses to the midpoint of $143 million, which is approximately flat when compared to 2024, despite expected increases in total production and cost pressures we are seeing from electric utility rates at Bear oil, which represents a large portion of our total LOE. We are also guiding Magnify EBITDA to a midpoint of $5 million in 2025, up from $3 million of EBITDA generated in 2024. The company's total capital investment for the fourth quarter was $15.3 million. Approximately $10 million of this capital was invested at Beta in our development drilling program and the completion of the electrification and emission reduction facility project. The remaining capital was invested in non-operated drilling in the Eagleford and East Texas, as well as various capital workovers and facility projects across our assets.

Our 2025 capital program is budgeted to be between $70 million and $80 million. The majority of our capital will be invested at Beta, with $30 million allocated to the development program and additional capital to further upgrade our drilling rigs. In 2024, we completed two wells with excellent results, which increased overall Beta production by approximately 15%. Based on these results, we intend to complete six wells in 2025 with high expectations of production growth. The C48 well, the first of the six wells to be completed in 2025, was drilled in the fourth quarter of 2024 and completed in mid-February due to equipment availability issues. The C48 is our first horizontal completion in the C sand. Similar to the A50 and C59 wells drilled in 2024, the completion of the C48 well was initially designed to target the D sand.

However, drilling conditions encountered in the D sand and the attractive geologic characteristics observed in the logs of the C sand led to the decision to complete the well as a C sand producer. We are currently drawing the well down and will share the details of this production when we have at least a month of production data. The remaining five completions in 2025 are planned as D sand wells. However, we always have the option to complete any of the A through D sand formations in this SACPAY reservoir based upon the log data we acquire while drilling. The planned 2025 completions also include the A45 well, which was the first well spotted in our drilling program at Beta in early 2024, but was deferred due to equipment problems leading to wellbore instability issues.

Capital costs for the new wells in the 2025 program is estimated to be between $5-$6 million per well. Like the A50 and C59 wells drilled in 2024, we expect quick paybacks and rates of return of approximately 100%. We have laid out some economic results to date of the A50 and C59 wells in the investor presentation available on the Amplify website and the type curve for the wells we plan to complete in 2025. Our updated investor presentation also includes a map of our next 25 planned locations at Beta. This map represents the locations we currently have classified as PUDs. However, based upon the estimated ultimate recovery of the field using original oil in place calculations and analogous field recovery factors, there will likely be additional development locations after the completion of the initial 25 wells, which our technical team is continually evaluating.

In addition to the development drilling at Beta, we also have capital allocated for facility investments, with the largest component of this capital being an estimated $8 million to upgrade a two-mile pipeline that ships all produced fluid from platform Eureka to platform Elly. We perform extensive mechanical integrity testing each year to our critical equipment and pipelines and take a proactive approach to upgrade any equipment that our internal and external experts deem necessary. Our 2025 budget includes an estimated $12-$15 million investment in the participation of very attractive non-op drilling alongside experienced operators in both our East Texas and Eagleford positions. In East Texas, we are participating in the completion of four non-op development wells, two Cotton Valley and two Haynesville, in which we have a 25%-30% working interest. We expect these wells to be completed and online by mid-year.

In the Eagleford, we are participating in 14 gross, 0.7 net new development wells and two gross, 0.4 net recompletion projects, all of which are scheduled to be completed in the first half of 2025. The majority of the remainder of our 2025 capital will be invested in active capital workover programs in Oklahoma, East Texas, and Bear Oil, which includes artificial lift conversions, recompletes, and well reactivation, as well as facility upgrade projects primarily in Bear Oil and additional investments in Magnify Energy Services. Some of the facility projects at Bear Oil are intended to improve the efficiencies at our CO2 plants, which will reduce our power usage, resulting in an expected savings of over $500,000 per month starting in the second half of 2025. We expect these savings to persist in the following years, significantly increasing the profitability at Bear Oil.

In regards to Magnify, we intend to invest $1.4 million in additional company-owned compressors, vacuum trucks, and other ancillary oil field service equipment. Since its inception in late 2023, Magnify has generated $3.7 million of adjusted EBITDA, with a capital investment of only $1.7 million. We expect Magnify to generate approximately $5 million of EBITDA in 2025, with a run rate EBITDA of approximately $6 million by year-end, with an anticipated total cumulative investment of only approximately $3 million. In addition to the cash flow generation potential of Magnify, this business line is extremely valuable to Amplify, as it allows us to more efficiently operate and manage our mature asset base in East Texas and Oklahoma. In regards to the Juniper assets, Juniper is currently drilling a two-well pad in the DJ Basin, and we anticipate fracking these wells sometime in the second quarter.

We are currently working with the Juniper team to evaluate the potential for additional development in both the DJ and Powder River Basin in the second half of 2025 and looking forward to 2026. With that, I will turn it over to Jim.

James Frew (SVP and CFO)

Thank you, Dan. I would now like to discuss the following items: fourth quarter financial performance, balance sheet and liquidity, and hedging. With respect to fourth quarter financial performance, the company reported a net loss of approximately $7.4 million compared to $22.7 million of net income in the prior quarter. The change was primarily attributable to a non-cash unrealized loss on commodity derivatives in the fourth quarter compared to an unrealized gain in the prior quarter. Excluding the impact of unrealized loss on commodity derivatives, in addition to other one-time impacts, adjusted net income was $5.1 million for the fourth quarter. For the year, net income was $13 million, and adjusted net income was $35.8 million. Adjusted net income was up 48% in 2024 compared to 2023. Fourth quarter adjusted EBITDA was $21.8 million, which was slightly below expectations.

As Dan mentioned, we had some unexpected downtime at Beta due to increased well failures that reduced production and increased workover costs. However, we now have those wells back online, and production has increased. Full year adjusted EBITDA was $103 million, in line with our guidance and up 17% compared to 2023. In total, fourth quarter lease operating expenses were approximately $35.1 million, which was in line with expectations. As I just mentioned, we did have higher LOE at Beta due to an increase in expense workovers. However, that was offset by lower LOE at Bear Oil due to a one-time benefit as the result of an accounting adjustment. For the year, total LOE was $143 million, or $19.95 per BOE, which was in line with our guidance.

With respect to other costs, fourth quarter GPT costs were $4.5 million, or $2.62 per BOE, while production taxes were $5.4 million, or 8% of oil and gas revenue. Cash G&A in the fourth quarter was $6.3 million, and we incurred $3.7 million of interest expense. GPT, production taxes, cash G&A, and interest expense were all in line with expectations. With respect to capital, Amplify invested $15.3 million in the fourth quarter, which was slightly higher than expectations. The company's capital allocation was approximately 65% for the Beta facility projects and development drilling, with the remainder distributed across the company's other assets. Free cash flow, defined as adjusted EBITDA less CapEx and cash interest expense, was $2.9 million for the fourth quarter of 2024. Amplify has now generated positive free cash flow for 10 consecutive quarters, illustrating the strong, sustainable cash-generating potential of our mature, diversified asset base.

As of December 31, Amplify had $127 million of debt outstanding under its revolving credit facility. Fourth quarter net debt increased from the prior quarter due to expected changes in working capital and increased development activity, primarily at Beta. At year-end, the company's net debt to last 12 months adjusted EBITDA was 1.2 times. As a result of the announced transaction with Juniper Capital, Amplify is currently working on integrating the newly acquired Rockies assets into the Amplify organization. Furthermore, the company is pursuing additional financing in connection with the transaction prior to close. Amplify intends to update the market with developments on the transaction as they progress. 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 covering the second half of 2025 through year-end 2026 at an average price of $68.10 per barrel.

We also added natural gas collars for a portion of 2027, with a weighted average floor of $3.63 per MMBTU and a weighted average ceiling of $3.98 per MMBTU. As of March 5th, our forecasted PDP crude oil production was approximately 70-75% hedged for 2025 and 25-30% hedged in 2026. On the gas side, our forecasted PDP production is hedged 85-90% for 2025 and 2026 and 15-20% hedged in 2027. 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.

Martyn Willsher (President and CEO)

Thank you, Jim. Yesterday, we provided standalone operational and financial guidance for Amplify in 2025. Following the close of the Juniper transaction, we will update guidance for the combined company. As noted in our press release, we have provided additional information about the Juniper assets in our 2025 Beta development plan and our latest investor presentation available on our investor relations website. As we look ahead, we are excited about Amplify's future. Amplify remains committed to exploiting the long-term value potential of the Beta field, and we anticipate strong growth for oil production from the area in 2025. This enthusiasm is warranted by the strong results from the A50 and C59 wells, which have break-even prices below $35 per barrel and compare favorably to the economics of the best oil development plays in the country.

The successful closing of the Juniper transaction anticipated in the second quarter will provide substantial benefits to the company and creates the flexibility to consider a range of value-maximizing opportunities for our existing assets. In summary, our team is excited for the opportunities in front of us, and we believe we have all the elements in place to make 2025 a very successful year for the company and its stakeholders. With that, Operator, we are now open for questions.

Operator (participant)

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. We'll pause for just a moment to allow everyone an opportunity to signal. Our first question today will come from Jeff Grampp with Alliance Global Partners.

Jeff Grampp (Analyst)

I want to start first in Beta. I want to dig in on this CSAN versus DSAND kind of dynamic with the upcoming well result. Can you give us a little bit of context, I guess, like how much legacy development or production is derived from the CSAN? How productive is that across the acreage position? Also wondering if we should be adjusting our expectations for well performance at all on this upcoming well relative to the first couple of well results and the type curve data that we have out there. Thanks.

Dan Furbee (SVP and COO)

Hey, Jeff. This is Dan. CSAN historical development versus DSAND. Going back in history, the majority of all these wells were drilled in the 1980s by Shell, and they were drilled as more or less vertical wells, as we talked about before, cutting through all sands, A through D, even some through A through F, and all the production is comingled. CSAN and DSAND performance in terms of a standalone horizontal well, like we drilled the last two DSAND wells horizontally, not a lot of data to go off of. Our type curves were derived off of volumetrics and some other reservoir calculations. That's how we did the DSAND. The CSAN result, we expect good results. The reservoir looks good. Like we said, we completed the well a couple of weeks ago. These wells typically take a couple of weeks.

You flow back water for a little while, then you start seeing oil cuts, and then you draw down the pressure, and the oil increases over time. We're currently drawing down the pressure. We see a good oil cut right now. In terms of expectation of the C versus the D sand, like I said, there's not analog wells to go off of a standalone C horizontal versus D horizontal either. The reservoir characteristics of the C versus the D is not as good, but we still expect that the C sand will be an attractive target that will yield good results across the field.

Jeff Grampp (Analyst)

Great. Thanks. That's really helpful. My follow-up for the planned new drills for this year, can you give us a flavor of how much of a step out are these relative to the prior wells we've drilled? Are we going into new fault blocks? Are we just kind of offsetting areas that have been kind of proven already? What's kind of the, I guess, risk appetite for offset wells versus kind of jumping into new fault blocks?

Dan Furbee (SVP and COO)

Yeah. Low risk compared to what we've done so far. The two wells we brought on the DSAN, the A50 and the C59, each of those were drilled in the two main fault blocks we're targeting. We call it the main fault block and our southern fault block. The first well we're drilling that we're spotting here very soon will be in the same fault block as the C59 and expect to be very low risk in terms of the reservoir and the quality. The most are wells that will be in that fault block, or what we call the main fault blocks, where the A50 is, and a lot of well results there as well. We do not see these as step outs from what we've done so far.

Jeff Grampp (Analyst)

Okay. Great. Thank you guys for the details. Appreciate the time.

Dan Furbee (SVP and COO)

Yep.

Operator (participant)

As a reminder, if you'd like to ask a question, please press Star One at this time. We will move to our next question from Subash Chandra with Benchmark.

Subash Chandra (Analyst)

Is there an oil price where you might review your 2025 CapEx plan?

Martyn Willsher (President and CEO)

Hey. Good morning, Subash. This is Martyn. I think, obviously, we've seen a lot of volatility in the oil price. I mean, I think six weeks ago, it was north of $75 a barrel, and now it's $66-$67 a barrel. With our Beta development specifically, I think we're still comfortable in that price range. Obviously, if prices were to continue to go down from a free cash flow management perspective, we'll continue to look at it. We do have a lot of development this year coming online in both the Eagle Ford and East Texas as well, which is the East Texas is obviously gassier. We wouldn't anticipate any adjustments on those particular projects. I think as you get into the second half of the year, you'd maybe kind of take a look at things if prices really continue to go down.But at present, we're very comfortable with what we have planned, especially with the hedging we have on the oil and gas sides this year.

Subash Chandra (Analyst)

Okay. Yeah. Maybe this is a difficult question to answer, but do you think by the time the deal closes, there's much stub Capex from the Juniper portfolio, or do you think their portfolio is more front-end loaded and less in the back half?

Martyn Willsher (President and CEO)

They're currently finishing up the drilling of the two DJ wells that Dan mentioned. I actually expect those to be finished drilling this weekend. From there, we expect to complete those after the merger closes, sometime in kind of the second half of the second quarter. From there, we obviously have the flexibility on what we will do for the remainder of 2025 and 2026. Luckily, there's not a lot of near-term lease issues, some things that we want to consider in the DJ specifically. For the most part, that acreage position is either held by production or long-term leases. We have a lot of flexibility there in terms of what we would want to do from a drilling perspective.

Certainly, we're going to consider that as we put together the plan for the remainder of 2025 and/or the plan to kind of get going in 2026.

Subash Chandra (Analyst)

Okay. Thanks. Yeah. I guess then finally, the Magnify '25 outlook, that's a standalone, not a pro forma outlook. But what do you think the potential is for Magnify with the Juniper assets, if any?

Dan Furbee (SVP and COO)

It is definitely something we'll start looking at. Right now, our Magnify services are limited to East Texas and Oklahoma. It started in East Texas really as a lot of competition for services with some of the Haynesville activity, especially the Haynesville moving our way. We found it better to bring some of that stuff in-house. We saw compressor rates going up. We saw swab rates going up, slick line units, all those different items. We delved into it there. Yeah, you're right. We're not expanding beyond Oklahoma and East Texas in our budget currently. I think this year, we'll take a hard look at the entire Wyoming area we have now with kind of that region being the Powder, DJ, and/or Bear Oil asset up there. We kind of have a large aggregate of assets in one area.

That's something to be looking at for Magnify.

Subash Chandra (Analyst)

Okay. We'll stay tuned. Thank you.

Operator (participant)

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

Jeff Grampp (Analyst)

Great. Thank you. Before I get to my final remarks, I do want to touch on one question I received earlier and make sure that it's clear. Regarding the A45, we've deferred that from Q4. One of the reasons, or the key reason, is that our development program this year is going to be Eureka weighted. A45 was drilled off the Ellen platform. The next three wells that we will be drilling in the 2025 Ellen program are all off Eureka. It does take a little bit of time and money to switch from Eureka to Ellen. The reason why that well, while we went ahead and finished the C48, the A45 will be later in the year is because we're going to drill off Eureka for the first, call it, two, three quarters of the year and then move to Ellen later in the year.

That was one clarification I wanted to provide on the '25 Beta development program. With that, 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 our stakeholders. We really appreciate you participating in the call today. As always, if you have follow-up questions, please reach out to us directly. Thank you.

Operator (participant)

This does conclude today's Amplify Energy's investor conference call. Thank you for your participation. You may now disconnect.