Amplify Energy Corp (AMPY) 2022 Q3 法說會逐字稿

Welcome to Amplify Energy Third Quarter 2022 Investor Conference Call. Amplify's operating and financial results were released yesterday after market close on November 1, 2022, and are available on Amplify's website at www.amplifyenergy.com. (Operator Instructions) Today's call is being recorded. A replay of the call will be accessible until Wednesday, November 16, by dialing (800) 654-1463 and then entering access code 10110635. 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 third quarter of 2022. Joining me on the call today is Martyn Willsher, Amplify's President and Chief Executive Officer.

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 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-Q 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 provide an update regarding our assets in Southern California, followed by our third quarter highlights and an operational update. I will then discuss the third quarter results in greater detail and provide updates to our hedging program, balance sheet and 2022 guidance. Martyn will conclude our prepared remarks with comments regarding performance during the quarter, current projections and strategic goals. We'll then have a question-and-answer session before concluding this call.

I will begin with an update regarding our Southern California assets. Since our last quarterly update, Amplify has made significant progress towards final resolution of all criminal and civil proceedings and continues to advance the permanent repair procedures needed to replace the damaged section of the pipeline and return the Beta field to production.

As we previously announced, we reached an agreement in principle with the plaintiffs in the class action to settle all civil claims against Amplify and its subsidiaries. On October 17, the plaintiff's counsel filed a motion for preliminary approval of the final settlement agreement, and that motion is currently noticed for a hearing with the court on November 16. The settlement amount of $50 million will be funded under the company's insurance policies.

During the third quarter of 2022, we also announced that Amplify had reached agreements with federal and state authorities to resolve all criminal matters involving the company and its subsidiaries stemming from the incident. The resolution of these matters contemplates an aggregate fine of approximately $12 million, payable installments to federal and state authorities over the next few years; probationary periods; and reimbursement of certain government agency response costs.

The company also agreed to implement certain compliance measures, including installation of a new leak protection system and increased remote-operated vehicle inspections of the pipeline. With the resolution of these matters substantially complete, we are concentrating on safely repairing the damaged sections of the pipeline and bringing the Beta field back online.

On October 1, we announced that Amplify received the Nationwide Permit 12 from the U.S. Army Corps of Engineers to proceed with the permanent repair plans, which were reviewed and approved by PHMSA earlier this year. Repair operations are currently underway to remove and replace the section of the pipeline damaged by anchor strikes on 2 shipping vessels in 2021.

After repair procedures are complete, the pipeline will undergo a series of safety integrity tests, as required by both federal pipeline safety regulations and the October 5, 2021 PHMSA corrective action order. We anticipate that PHMSA will review the pipeline restart plan, and once finalized, the company will begin the process of bringing the Beta field back online.

Repair operations have progressed as expected and are subject to the various reviews and approvals previously discussed. We currently estimate bringing the Beta field back online by the end of the first quarter of 2023.

Amplify's actions during the course of the last 12 months reflect the commitments we made immediately following the incident to the communities and environment impacted by the release. We worked diligently to support the successful cleanup and remediation efforts and continue to work cooperatively with the various state and federal agencies involved with these matters. Furthermore, we continue to aggressively pursue our substantial claims for damages against the vessels that struck and damaged our pipeline and their respective owners and operators and the Marine Exchange of Southern California that failed to notify us of the anchor strikes.

Now on to the quarter. Production for the third quarter averaged approximately 21,000 BOE per day, an increase of 3% from 20,400 BOE per day in the second quarter. The quarter-over-quarter increase was driven by recent development activity in Eagle Ford, accelerated workovers in Oklahoma and the return to normal operations in Bairoil after the annual maintenance turnaround in the second quarter.

Third quarter adjusted EBITDA was approximately $30.8 million compared to $16.3 million in the prior quarter. The increase was attributable to higher production, lower operating expenses, timing variances regarding the recognition of LOPI insurance proceeds and lower commodity hedge settlement payments. Capital spending during the third quarter was approximately $9.9 million primarily related to workover activity in Oklahoma, nonoperated development in the Eagle Ford and facilities maintenance at Bairoil and Beta.

Free cash flow, defined as adjusted EBITDA less CapEx and cash interest expense, was $17 million in the third quarter of 2022, which compares to $14.3 million in the first half of the year. With Beta expected to restart early next year, we anticipate free cash flow generation to accelerate and are now projecting cumulative free cash flow of $235 million through year-end 2024 at current commodity prices.

Now for an update on our operations. In Oklahoma, we continued our workover program, running 3 rigs focused on returning offline wells production and artificial lift optimization. As a result of this program, our Oklahoma production increased approximately 5% in the third quarter from 6,500 to 6,800 BOE per day, and the field achieved its highest quarterly production rate since the first quarter of 2021. For the remainder of 2022, we expect to continue an active workover program to manage our cost profile and drive incremental free cash flow.

At Bairoil, processing facilities returned to normal operating levels after completion of the annual maintenance turnaround last quarter, resulting in production of 3,600 BOE per day and lower operating expenses. We will continue to utilize targeted workover activity and well stimulations to drive further operational improvements and efficiencies and improve production performance.

In East Texas and North Louisiana, we remain committed to efficiently managing production and costs while pursuing high-return workover in joint development projects. Results from the nonoperated completions, which we participated in during the second quarter, have continued to exceed expectations, and we intend to participate in similar high-return projects into 2023.

In the Eagle Ford, third quarter production increased 25% from the previous quarter primarily resulting from successful development activity earlier in the year. We are currently participating in 11 gross, 1 net additional development projects, including 2 refracs, which are projected to be online in the first quarter of 2023.

I will now turn the call over to Jason to provide a detailed review of our financial and operational results.

Thank you, Martyn. Production for the third quarter averaged approximately 21,000 BOE per day with a commodity mix of 31% oil, 19% NGLs and 50% gas. Once Beta returns to production next year, the company expects the product mix to return to approximately 40% oil with the low decline and increasingly oil-weighted nature of our diverse assets further driving long-term profitability.

Total oil, natural gas and NGL revenues for the third quarter were approximately $112.8 million before the impact of derivatives compared to $112.9 million in the second quarter. Other revenues were $13.5 million for the quarter compared to $8.9 million in the second quarter.

For the third quarter, the company recognized $13.3 million of LOPI proceeds, which represents 3 months of LOPI payments compared to $8.8 million or 2 months of local payments for the prior quarter. As discussed during our prior earnings call, Amplify's LOPI insurance policy is effective for 18 months following the day of the incident, and the company will continue to receive payments until the earlier of the expiration of the policy or until Beta's return to full production.

Lease operating expenses for the third quarter were approximately $32 million or $16.56 per BOE, a decrease from $33.3 million or $17.91 per BOE for the second quarter primarily attributable to lower workover costs at Bairoil. GP&T this quarter was $7.5 million or $3.87 per BOE compared to $7.3 million or $3.92 per BOE in the second quarter. I would like to note that we expect GP&T to decline in future quarters as the East Texas gas NBC expires this year and the Oklahoma NGL NBC expires in June of 2023.

Production and ad valorem taxes this quarter were $9.2 million or $4.73 per BOE compared to $8.6 million or $4.64 per BOE in the prior quarter. Third quarter cash G&A totaled $6.1 million or $3.16 per BOE compared to $7.7 million or $4.16 per BOE in the second quarter primarily due to a decrease in certain professional and advisory.

Adjusted EBITDA in the third quarter totaled $30.8 million, an increase of approximately $14.5 million from $16.3 million in the prior quarter. As previously discussed, the increase was primarily attributable to higher production, timing variance regarding the recognition of LOPI insurance proceeds and lower operating expenses and head settlement payments. Cash capital spending for the third quarter was approximately $9.9 million, a decrease of $3.6 million from the second quarter primarily related to reduced capital in the East Texas and Bairoil.

Free cash flow for the third quarter was $17 million compared to negative $0.6 million in the prior quarter. The quarter-over-quarter increase was primarily related to the scheduled roll-off of out-of-the-money commodity hedges in addition to the previously noted reductions in capital spending and LOPI payment recognition during the second and third quarters.

On to the hedge book. As evidenced by our free cash flow generation this quarter, we are now starting to realize the benefits from the scheduled roll-off of our hedge book, and the company will continue to capture additional upside in the current commodity price environment as we roll off additional out-of-the-money hedges in the coming quarters. Currently, we are approximately 70% hedged for the balance of 2022 and 50% hedged in 2023 across all commodities.

Our crude oil production is approximately 85% to 95% hedged for the remainder of the year and 50% to 60% hedged for 2023. On the gas side, we are approximately 85% to 95% hedged for the balance of 2022 and 70% to 80% hedged for 2023. As a reminder, when we return Beta field to production, those crude oil volumes will be completely unhedged, which may provide additional upside depending on prevailing prices.

Moving on to our balance sheet. As of October 28, Amplify had net debt of approximately $179 million, consisting of $205 million outstanding under our revolving credit facility and $26 million of cash on hand. For the remainder of 2022 and into 2023, we'll continue to allocate the majority of our free cash flow to improving our balance sheet and reducing our total debt outstanding. The company's fall borrowing base redetermination process is currently underway, and we will provide further updates as they become available.

On to guidance. As detailed in the earnings release last night, we have tightened our full year 2022 guidance ranges for production, adjusted EBITDA and free cash flow. Additional guidance details will be provided in our earnings release and can be found in the latest investor presentation currently available on our website. I'll now turn the call back to Martyn.

Thank you, Jason. Our near-term strategy remains focused on continuously enhancing our free cash flow profile and rapidly delevering our balance sheet. As we progress into 2023, we expect to not only continue generating the current level of quarterly free cash flow, but we anticipate materially increasing our free cash flow profile as our hedge book continues to roll off and the Beta field has returned to production.

Currently, our forecasted 2022 to 2024 cumulative free cash flow is estimated to be approximately $235 million at current strip pricing, and we are projecting to improve our leverage to under 1x by the third quarter of 2023. As Jason mentioned earlier, we are currently working with our lending group on the fall borrowing base redetermination and are exploring various solutions to extend or replace the current facility, which matures in the fall of 2023.

Lastly, I'd like to express my appreciation to the company's employees for their outstanding efforts and dedication, particularly over the last 12 months. We have made significant progress towards final resolution of the legal matters related to the incident and are actively pursuing our claims against the ships that caused damage to our pipeline in 2021.

Finally, we remain focused on progressing repair operations with the anticipation of bringing the Beta field back online early in 2023. With that, operator, we are now open for questions.

(Operator Instructions) And our first question comes from John White with ROTH Capital.

And congratulations on all the progress you've made on the legal matters over the past number of months. I'm sure that's very distracting, but it looks like a lot of progress has been made. At Beta, what exactly is going on? Are there damaged sections of the line being replaced by new sections of pipe? Or is there a lot of welding going on? Can you give us some more detail on the actual operations?

Sure. So the primary repair is to about a 250-foot section. That's right where the actual crack occurred. That section of the line has been removed and brought to the beach, so to speak, to the port. That's the biggest section of pipe. That section will then be replaced with essentially new pipe. That's kind of the -- where we are in the progress right now. There's an 80-foot section that also has to be replaced and the clamp that has to be placed. Those 2 procedures will obviously be a little bit shorter and easier. The biggest section of the pipeline has been removed and already brought in.

So that process is ongoing, and we expect that to take a few more weeks. After that, as we mentioned in the -- in our statement, there's a series of tests, both hydrostatic testing and then in-line inspections that we complete and then are reviewed by PHMSA and [DASI] as part of the restart plan. And once that's approved, then we can start putting oil through the pipeline again.

Obviously, it's in -- we're kind of giving ourselves a little bit of room on timing just because we don't know how long it will take to do the review. But like I said, we expect this will be done prior to the end of the first quarter and hopefully before that.

That's good detail, and good luck on that. On your lawsuit against the shipping companies, and I understand if you don't want to comment. But as I understand it, the preponderance of the evidence that the Coast Guard has revealed is pretty strong. Are you anticipating a settlement prior to the trial date? Or do you think you're going to go to trial?

Well, there could be -- there's different forms that this could take. I don't want to get into strategy or how strongly I believe about this case. But you've noted that we mentioned that there were anchor strikes. We believe there's a substantial amount of evidence of that.

But in any event, these damages are ongoing. Until this Beta field has returned to production, we continue to lose revenue as a result of, quite frankly, the damage caused. It has really nothing to do with the spill event itself. It ties back to the actual time of when these ships caused the damage. So there's a little bit of a difference in what we are suing for individually versus what we are doing for on behalf of the insurance companies, which is tied more to the contribution -- to the cost of the actual spill event itself.

So I said this is going to be an ongoing process. I think I said these are 2 of the largest shipping companies in the world. So it might take a little bit of time. Or it might get settled quickly. It really just depends on how commercial things get.

And our next question comes from Jeff Robertson with Water Tower Research.

Martyn, at Beta, 2 questions. One, will the work you all have done to restore production have much of an impact on operating costs for those assets as you restart them? And secondly, you all had talked previously before the spill about some redevelopment opportunities or some recompletion opportunities. Can you just provide an update on where that might stand in your capital allocation process either for 2023 or maybe even 2024?

Those are great questions. Let me start with the operating cost first. One of the things we've done this year is we've continued to electrify the platforms. So they're going to be running on more shore power versus diesel power. This obviously helps with air quality standards and other things as well. So we have been making changes even while we've been down in order to further reduce the fixed cost going forward.

When we first come back online, one of the things that we'll note is that we're projecting kind of a reduced rate for some time because, obviously, being offline for what could be 17, 18 months by the time we come back online, we want to make sure that we're being conservative and not overprojecting crude volumes coming straight out of the gate.

And so we have a ramp-up of our -- of the production from about 50% of the production rate prior to the event, and that is not including the impact of royalty relief anymore. So we ramp up from about 50% up to 100% over time. We have the crews already on the platform. We have the rigs ready to go for whenever we get back online.

So obviously, our first primary responsibility is to kind of get all the existing wells back online as quickly as we can. So that's where we'll start our focus. We do still have all the permits in hand for the -- for what we were doing prior to the event, which included, as you may recall, a couple of smaller projects that we were planning to do in late in 2021 and then 2 large projects in early '22, which were -- had some real potential to increase production of the field.

Those projects are still very valuable and even more so at current pricing. So I would expect we will revisit that once we kind of get the Beta field back and most of the existing wells back online. I can't give you an exact timing of that yet. It really depends on how quickly we get the existing production back online and kind of fully restored.

Okay. So there's still -- those development opportunities are still -- is it fair to say it's still very attractive, especially in today's commodity price world?

Yes, they're even -- they're far more. Obviously, we did lose royalty relief, but that was because -- pricing has jumped up so much. And those projects are much more valuable now even without royalty relief than they were when we originally intended to do them.

And just a question on the hedge book structure. Jason, for 2023, are the hedges spread pretty evenly through the year? Or will they roll off as the quarters progress?

They'll roll off a little bit. It's fairly even. I mean we're not projecting a sizable decrease in production volumes throughout the year. We have some of the joint development that's going on in the Eagle Ford and East Texas that'll help offset that. Plus the benefits of the workover program in Oklahoma keeps it fairly flat and notwithstanding kind of the nature of the assets with Beta and Bairoil.

So it will roll off a little bit but not substantially. As you kind of look at them, the structures are a lot more advantageous than what we had this year. So we'll have a lot more benefit as we kind of roll forward. And just speaking specifically to the gas side, I mean, we are -- only have [color] for '23 at this point and the floor is about [3 50], and they call out just under $6. So kind of right in that sweet spot when we'll see potential upside as we roll forward.

So I think at this point, we're going to take some questions that we received as well from various investors as well. Jason?

Perfect. Yes. And just consistent with what we did last time, that we received a number of questions from some investors and have consolidated that. And we'll ask a few of those here and just continue to encourage people to send those along our way, and we'll roll this forward as we continue with this in future quarters.

The first one that hasn't been touched here is in relation to inflationary CapEx environment and kind of our plans that roll forward through our 3-year free cash flow forecast. So the specific question is did we raise the CapEx in our free cash flow slide. And what are we seeing from an inflationary aspect? And what are we doing that's different from other people to try to mitigate that?

Yes, certainly. Thank you, and thank you for first submitting this question. First of all, we have increased capital through the '23 and '24 cycle. A lot of that has to do with finalizing a little bit more of our planning related to East Texas and Eagle Ford development during that time period. We have seen inflation, obviously, on the drilling side, even though it's a non-op partner, and those are already incorporated into the '23 and '24 events. Obviously, the returns are still very, very strong as well.

So we're not immune to inflation. And certainly, we've seen it on kind of the base LOE side earlier in the year. It's mitigated somewhat lately, but we've seen it across a wide range of things, everything from chemicals to saltwater disposal and everything in between.

So we have certainly accounted for that going forward, and in our capital forecast, that's in there as well. Obviously, the other capital forecast is more around facilities, and kind of our workover projects haven't seen that same level of inflation. The kind of work over projects that we do are a little bit easier and kind of easier to kind of manage from an inflationary perspective. So we haven't seen quite as much inflation on those.

So we have, like I said, incorporated all of that into the future projections. And as we get more granularity into kind of future plans, we will continue to update and revise that future cash flow forecast and, obviously, with the next one coming after Q4 with the full year 2023 outlook.

Great. And the last question that hasn't been touched on that we received from a number of people is can we provide any additional color on the pending RBL maturity and the plans to address that through an extension or refinance.

Certainly. So as we mentioned, we are currently talking to our RBL lenders primarily about an extension in the near term. All of this financing becomes a lot easier once Beta comes on -- gets back online. So we are trying to extend that fairway for a certain amount of time in order to give us a little bit more flexibility. We will look at all -- any and all kind of options to refinance. That could mean kind of an RBL with fewer banks. It could mean a new financing structure completely.

So there's a lot of alternatives out there and quite frankly, we could do it in the near term, but it becomes a lot more attractive and easier once Beta is back online. So we're trying to give ourselves a little bit more time to get that done. So we will have something on that, hopefully, in the coming months, and we'll update the market when we have that.

Great. I think that concludes the Q&A portion of the call. So I'll turn it to Martyn for some closing comments.

Thank you, Jason. I'd just like to thank everyone for participating in the call today. We're continuing to work diligently to finish the year strong on the production side and really focus on getting Beta back online as early in the first quarter as we can. We will continue to update all of our stakeholders on our progress. And as always, if there's any questions, please don't hesitate to reach out. Thank you, everyone.

Thank you, ladies and gentlemen. This concludes today's teleconference. You may now disconnect.