Welcome to Amplify Energy's Fourth Quarter 2021 Investor Conference Call. Amplify’s operating and financial results were released yesterday after market closed on March 9, 2022 and are available on Amplify's website at www.amplifyenergy.com. During this conference call, all participants will be placed in a listen-only mode. Today's call is being recorded. A replay of the call will be accessible until Thursday, March 24th by dialing 855-859-2056, and then entering conference ID number 8984535, or by visiting Amplify's website at www.amplifyenergy.com. I would now like to turn the conference call over to Jason McGlynn, 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 fourth quarter of 2021. Joining me on the call today is Martyn Willsher, Amplify's President and Chief Executive Officer. Before we get started, we'd 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 assurance 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, that 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 will start us off with an update of the Southern California Pipeline Incident. I will then review the fourth quarter results and provide updates on our hedging program and balance sheet. Martyn will then follow up with our year-end 2021 proved reserves and guidance expectations for the full year 2022. Following our prepared remarks, we will have a question-and-answer session and Martyn will conclude this conference call with closing remarks.

Before we get into the quarterly results and our 2022 outlook, I would like to spend a few minutes providing an update regarding the Southern California release. First and foremost, I cannot stress enough my gratitude to our Unified Command partners for their collaboration and professionalism as we mobilized a robust response effort to the events in Southern California. This includes the United States Coast Guard, the California Department of Fish and Wildlife, Orange and San Diego Counties and various other federal, state and local agencies. Additionally, we are also grateful to the numerous volunteers, wildlife rescue organizations and the nearly 1,800 oil spill response contractors that we deployed as part of the response effort. On December 28, 2021, the United States Coast Guard announced that Unified Command had concluded clean-up operations in all counties impacted by the release event and Unified Command was officially stood down and the response phase was officially complete on February 2 of this year. Working with federal pipeline safety regulators and world-class engineering and dive teams, we designed an approved temporary repair plan for the damaged pipeline and have completed this phase of the work by safely and successfully removing any oil in the pipeline that remained following its shut-in on October 2, 2021. We continue to work cooperatively with the relevant regulatory agencies to safely and promptly advance our permanent repair plan for the pipeline and bring the Beta field back online. Separately, last week, we filed a complaint against the two shipping companies and vessels whose anchors struck and damaged the pipeline causing the oil release in early October. We also filed claims against the Marine Exchange of Southern California, which failed to notify us of the anchor strikes when they occurred. Amplify filed complaints against these parties because their actions or inactions caused the October 2021 release event. This release event should never have happened and if any of these parties had notified Amplify, this entire incident could have been avoided. We remain committed to safely operating in a way that ensures the protection of the environment and the surrounding communities where many of our employees live and raise their families. We continue cooperating with all federal and state agencies investigating this matter and eagerly await approval from federal regulators and permitting agencies to complete the permanent repair plan and bring the Beta field back online. I will now turn the call over to Jason to provide an overview of our financial and operational results.

Thank you, Martyn. I'll first provide details of the company’s fourth quarter results, and then give an update on our hedge book, concluding with comments regarding our balance sheet. As mentioned in our earnings release, production for the fourth quarter averaged approximately 20,800 BOE per day, a decrease from 25,100 BOE per day in the third quarter of 2021, with the commodity mix of 31% oil, 18% NGLs, and 51% gas. Oil volumes were down this quarter as a result of the suspension of operations at Beta on October 2. For comparison, the Beta field produced an average of 3,700 barrels of crude oil per day during the third quarter. Total oil, natural gas, and NGL revenues in the fourth quarter of 2021 were approximately $86.3 million before the impact of derivatives, compared to $96.8 million in the third quarter. Other revenues were $6.8 million for the quarter compared to $0.2 million in the third quarter. The change in other revenues was primarily related to the receipt of loss of production income insurance payments of $6.7 million for the period from November 15, 2021 through December 31, 2021. Our LOPI insurance is effective for approximately 18 months following the incident, with payments starting after 45 days of non-production. Lease operating expenses for the fourth quarter were approximately $29.4 million or $15.34 per BOE, a decrease of approximately $5.1 million compared to $34.5 million or $14.92 per BOE in the third quarter, primarily due to the reduced workover activity at Beta. GP&T this quarter was $6.1 million or $3.20 per BOE compared to $5 million or $2.18 per BOE in the third quarter. The increase was primarily attributable to a one-time accounting adjustment related to our non-operated Eagle Ford property. Production and Ad Valorem taxes this quarter totaled $6.5 million or $3.42 per BOE compared to $6 million or $2.61 per BOE in the prior quarter. This increase is a function of higher revenue from improved commodity pricing, partially offset by lower production. Fourth quarter cash G&A totaled $6.2 million or $3.24 per BOE compared to $5.8 million or $2.50 per BOE in the third quarter. Adjusted EBITDA in the fourth quarter totaled $10.8 million, approximately $16 million less than the previous quarter. The decrease was largely attributable to the suspension of operations at Beta, partially offset by higher commodity prices, lower lease operating expenses, and loss of production income insurance payments received as a result of the incident. To mitigate being in an over-hedged position from the loss of production at Beta, the company entered into offsetting crude positions, which had an estimated $5 million negative impact on the quarter. Cash capital spending for the fourth quarter was approximately $3.5 million, a decrease of $7 million from the third quarter of 2021. The quarter-over-quarter decrease was primarily attributable to the suspension of operations at Beta. Free cash flow, defined as adjusted EBITDA less CapEx and cash interest expense, was approximately $4 million in the fourth quarter of 2021. Despite the substantial impact of the Beta incident, Amplify reported $84.7 million of adjusted EBITDA and over $40 million of free cash flow for the full year 2021, which exceeded internal projections and was a result of production outperformance within our diversified asset base and strong price realizations. Now to our hedge book. Due to the loss of production at Beta, the company entered into 420,000 barrels of offsetting crude positions for 2022. These trades were executed in late November of 2021 at a weighted average price of $66.86 per barrel, which compares to the current strip of over $100 a barrel. Currently, we are approximately 70% hedged for the balance of 2022 and 40% hedged in 2023 across all commodities, specifically our crude oil production is approximately 90% to 100% hedged for the remainder of the year and 50% to 60% hedged for 2023. I would like to note that our NGLs, which represent approximately 20% of our current production are completely unhedged in 2022 and 2023, enabling the company to participate in a rising commodity price environment. Lastly, as Martyn mentioned earlier, we are expeditiously working to bring the Beta field back online and those crude oil barrels will be completely unhedged when production is restored. Amplify’s March 2022 investor presentation contains additional details regarding our current positions and was posted to our website yesterday under the Investor Relations section. Moving onto our balance sheet. As of February 28, Amplify had net debt of approximately $203 million, consisting of $225 million outstanding under our revolving credit facility and $22 million of cash on hand. For the remainder of 2022, we will continue allocating the majority of our free cash flow to improving our balance sheet and reducing our total debt outstanding. We are currently marketing our non-operated Eagle Ford asset and are considering additional transactions that could accelerate the deleveraging of our balance sheet. I will now turn the call back over to Martyn.

Thank you, Jason. Yesterday, we announced Amplify’s 2021 year-end proved reserves estimates of approximately 121 million barrels of equivalent with a PV-10 value of $920 million based on SEC pricing of $66.56 per barrel for crude oil and $3.60 per MMBtu for natural gas, with approximately 98% of the proved reserves classified as proved developed. The product mix for our proved reserves was approximately 37% crude oil, 20% natural gas liquids, and 43% natural gas. Utilizing strip pricing as of February 28, 2022, the company's year-end 2021 proved reserves are approximately 120 million barrels of equivalent with a PV-10 value of $1 billion of which 118 million barrels of equivalent and $970 million of PV-10 value is classified as proved developed reserves. As a result of the incident at Beta, all production and pipeline operations at the Beta Field have been suspended and the asset’s PDP reserves have been reclassified as PDNP. Further, the company has shifted its resources to returning Beta to production, which has resulted in a modification to our future PUD development plans and a reduction in our PUD reserve estimates for 2021. These locations remain available to the company and can be reclassified as PUD reserves, should the company pursue additional development in the future. Additionally, we have now provided guidance expectations for full year 2022. Due to uncertainty regarding Beta’s restart timeline, our guidance does not assume Beta returns to production in 2022, but we will update our guidance when additional information is available. Our full-year 2022 average daily production forecast ranges from 18,500 to 20,500 BOE per day with the commodity mix of approximately 31% oil, 18% NGLs, and 51% natural gas. Our CapEx forecast for the year is approximately $20 million to $30 million, which is comprised of non-operated development projects in East Texas and Eagle Ford as well as high return workover projects and routine facility maintenance across our asset base. Approximately $7 million of the CapEx forecast will go towards non-operated development as we expect to incur $5 million for the completion of 3 gross, 0.6 net non-operated wells in East Texas and $2 million in the Eagle Ford to complete approximately 13 gross, 0.5 net non-operated DUCs that were drilled in 2021. In addition, we anticipate spending approximately $7 million in Oklahoma for rod lift conversions and ESP optimizations. The rod lift conversion project initiated in late 2018 has been successful in significantly reducing operating expenditures and recurring maintenance costs. Lastly, the company has budgeted approximately $11 million in 2022 for facility work and capital workovers at Bairoil, Beta, and East Texas. Ultimately, we anticipate generating approximately $40 million to $70 million of free cash for the year from adjusted EBITDA of $70 million to $100 million. Additional guidance details were provided in our earnings release yesterday and can be found in the latest investor presentation currently available on our website. In closing, we continue to believe we remain substantially undervalued in the current market due to our significant reserve value and cash flow generation potential. Our 2021 year-end total proved reserves now have a PV-10 value of approximately $1 billion at strip pricing as of February 28, 2022 and, as detailed in our investor presentation, our internal three-year projections currently forecast approximately $150 million to $250 million in cumulative free cash flow, which is approximately 50% of our current enterprise value. We are focused on continuously enhancing our sustainable free cash flow profile and delevering our balance sheet. The elevated commodity pricing environment also allows us to opportunistically augment our workover program in Oklahoma and explore additional non-operated development opportunities within our East Texas and Eagle Ford assets. Additionally, the recently announced marketing process of our non-operated Eagle Ford asset is expected to accelerate our commitment to delevering and we are evaluating additional accretive transactions that could further drive shareholder value. Our dedication to enhancing corporate and operational efficiencies, coupled with our diverse and mature asset base, differentiates Amplify as a leader in generating sustainable free cash flow. Our strong free cash flow, and leverage outlook supplements our ability to create significant long-term value for shareholders through asset reinvestment, accretive transactions, and return of capital initiatives. With that in mind, operator, we are now open for questions.

And you have a question in queue from John White with ROTH Capital. John, your line is open.

Good morning and congratulations on some nice results, despite the challenges you're facing.

Thank you, John.

Regarding the EBITDA guide in 2022 and your cumulative free cash flow number. How much insurance payments are included in those guidance numbers?

So for LOPI, we're projecting approximately $4.4 million per month.

And for what time period?

For the guidance, it covers the full 12 months. We hope to have Beta online sooner rather than later, but we are being conservative by using LOPI instead of projecting when Beta will be available in 2022. We will update this information when we have a clearer timeline for Beta's return.

Yeah. The only thing I'll add to that John is, as we noted in our K last night, LOPI works for 18 months and that is inclusive of a 45-day waiting period that gives you a little bit of view on how long it tracks through the three-year numbers.

Okay. 18 months in the cumulative free cash flow number, correct?

It started at the time of the incident of October 2 and it runs 18 months from there, but you have 45 days of non-payment as we noted multiple times. So, it runs into a little bit into 2023 through the first quarter.

Thanks very much. Why is the revolver being reduced $5 million a month starting in, well that started in February of 2022?

We went through our redetermination last fall with the bank group, and we were in the middle of that when this incident occurred. We paused the process, and as mentioned in our third-quarter information, we were reaffirmed at $245 million. Given the current circumstances and the need to understand the timeline better, the bank group requested some amortization to begin in February of this year, which will continue until our next redetermination, which we expect to kick off shortly and complete during the second quarter.

Okay. So, after the redetermination, the reduction in the revolver may cease, is that correct?

That is correct.

Okay. Well, those are my first two. I'll pass it on and I'll come back with some follow-ups.

Okay.

Okay. And there are no additional questions in queue. Mr. White, if you want to continue with your additional questions.

Sure. Thank you, operator. In your 10-K, you mentioned regarding Beta $90 million to $110 million of associated costs that have been incurred or may be incurred. Could you tell us how much has been incurred? And give us a little more detail on what those costs are for?

Yeah, I'll take that. So, the first part of that is, that's all actual and projected response for the remediation that occurred under the direction of Unified Command. As we noted, Unified Command has disbanded. So that was essentially all the costs that will be booked under remediation and certain legal fees. For that $90 million to $110 million, we did note that $99 million of average costs were incurred through 12/31. The piece of that that hits the income statement is the deductible payments and certain legal costs, which is about $1.6 million, so that left that number at about $97.4 million. Through the end of the year, we had received about $50 million or we have received about $50 million of insurance for costs and we've collected an additional $22.1 million through the 1st of March and we're continuing to move forward from there. So that gives you a little bit of detail on what that $90 million to $110 million accounts for, and then there is also plenty of information out there on what it doesn't include. So, it does include all the insurance costs moving forward and some of those other things, which that will be partially covered by insurance as well.

$99 million incurred in 2021?

Yes, that was booked. So, it wasn't all incurred, but that's what was incurred and projected to be incurred related to the remediation and certain known legal items.

Do you know how much was spent in 2021?

About $40 million and then there was an insurance receivable about $49 million, as I noted.

Thank you for that. I know despite Beta not being included in your guidance, you have a slide in your presentation on the reserves with a footnote that has an assumption of Beta restarting in about four months, is four months your expectation?

So, John, what we're trying to do there was kind of give bookends for our investors so that we can extrapolate. Obviously, we are hopefully moving along this permitting process for quite a while. We could certainly be back online in that July timeframe, if we were to receive the permits in fairly short order. So, this is a reasonable estimate of if we get the permits soon, then we can be back online as quickly as July. Obviously, there are potential delays and so we are trying to give our investors kind of a bookend of best-case scenario versus a worst-case scenario in terms of getting Beta online. Obviously, one does think that those projections don't include anything related to litigation, and obviously, we're offline for a reason, which is the damage inflicted on the pipeline and obviously we've filed a complaint related to that. So obviously, that’s all contingent and wouldn’t be reflected. But the longer you stay offline, the more damages you're incurring related to that. So those things are not reflected in that cash flow forecast, but we did want to provide as much information as we could to our investors.

I'm sure we all appreciate that. So, part of the Beta pipeline is in federal waters and part is in state waters, do you have available the number of federal permits you're going to have to get permits waivers approvals from the federal government and how many from the state government?

So this is the damages in federal waters and this is a federal jurisdiction item. There is some state involvement in asking questions and certain other things that they can move along. But this is really waiting on two permits. One is from PHMSA for the repair and the other one is from the Corps of Engineers. Those permits have been in process for quite some time and we've answered a lot of questions along the way. And so, we're hoping that we're kind of moving towards conclusion but like I said, we don't have a definitive timeline on exactly when we get those permits and so that's why we are, we're not ready to project an exact start time for Beta at this time, but obviously we're working as expeditiously as we can towards getting those two. Once we get those permits, it's a matter of testing, which falls into the PHMSA jurisdiction, we're going to be doing some hydrostatic testing and some in-line inspections. Just to once again make absolutely certain that the rest of the pipeline is in the great shape that we think it is and so nothing will be coming back online until this is all thoroughly tested and like I said that timeframe that we're talking about, if we got the permit soon we could be back online in July. So, let’s call it a three to four-month window. That's a reasonable timeframe for getting back online if there are no interruptions, once you get the permits.

Okay. So, two federal agencies and so, no state agencies approval needed?

Not at this time. Like I said, they have some input into the Corp’s of Engineers process, but there is no specific permit requirement at this time.

I appreciate it. Regarding your proposed divestiture of your non-operated Eagle Ford. Can you say who the operator is?

Yeah. All of our interest is in the heart of Karnes County, as the primary operator is Murphy, but there are also other operators of Devon BPX and Marathon that make up the majority of the rest of it.

But it's very largely Murphy, where we have the majority of our interest.

Yeah. I couldn’t remember whether it was Murphy or Marathon. What would be the borrowing base impact? How much of the Eagle Ford is in the borrowing base?

We can't really get into that too terribly much, obviously, we discuss these types of things with our bank group, but what we can give you a little bit of a viewpoint is on the reserve base, if you look at Slide 6 in our deck on the PD PV-10, it's $40 million out of $970 million. So, use that percentage and extrapolate, and that gives you a decent idea of what could be in there; maybe it could be a little bit more and it could be a little bit less, but that gives you a good working number on what could potentially happen there.

Again, I appreciate that. And thank you for your patience with all my questions. And I wish you the best of luck on getting Beta started and in your complaints against the other shipping companies.

Thank you, John. Really appreciate it.

And there are no further questions in queue at this time. We'll go to your closing remarks, please.

I'd just like to say thank you to everyone for joining us today. I really want to express my appreciation to all our company employees for their outstanding efforts, especially our California personnel who were working tirelessly alongside Unified Command for much of the fourth quarter. And I'd also just like to thank our stakeholders for all their continued support, both our investors and insurance companies and banks, and various other stakeholders that have worked very well with us during this period. And as always, please don't hesitate to reach out, if you have any questions. Thank you, everyone.

This concludes today's conference call. Thank you for participating. You may now disconnect.