Amplify Energy Corp (AMPY) 2020 Q3 法說會逐字稿

Welcome to Amplify Energy's Third Quarter 2020 Investor Conference Call. Amplify's operating and financial results were released earlier today and are available on Amplify's website at www.amplifyenergy.com. (Operator Instructions) Today's call is being recorded, and the replay of the call will be accessible until Thursday, November 19, by dialing (855) 859-2056, then entering conference ID 7283609 or by visiting Amplify's website, www.amplifyenergy.com.

I would now like to turn the conference over to Jason McGlynn, Vice President of Business Development 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 2020. Joining me on the call today is Martyn Willsher, Amplify's Interim Chief Executive Officer and Chief Financial 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 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 risk 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 we expect to file later today.

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.

With that, I will now turn the call over to Martyn Willsher. Martyn?

Thank you, Jason. During this call, I will provide comments on our third quarter performance, our hedging program and an overview of our liquidity position and balance sheet. I will then turn the call over to Jason to provide additional financial details for the quarter. Following our prepared statements, we will take questions, and I'll conclude with closing remarks.

Production for the third quarter averaged approximately 27,700 BOE per day, which mirrored second quarter 2020 production performance and exceeded our internal expectations. Notably, oil production volumes increased by 5% during the quarter to approximately 10,800 barrels per day from 10,400 barrels per day in the second quarter. This increase in oil volumes was primarily attributable to royalty relief Beta. However, it is important to note that all asset areas met or exceeded internal expectations despite intermittent third-party weather interruptions and reduced maintenance capital expense and these results demonstrate the sustainable value of our long-lived, low-decline assets.

Third quarter adjusted EBITDA was approximately $24.8 million, meaningfully exceeding internal estimates and validating the exceptional execution of our cost reduction initiatives and hedging program.

Capital spending for the third quarter was approximately $5 million, which was slightly above our internal expectations, primarily attributable to additional costs associated with our non-operated Eagle Ford asset. Remaining capital spending for the year will be $3 million and focus on high-return capital workover projects and facility maintenance expenses across our operated assets.

Free cash flow, defined as adjusted EBITDA less CapEx and cash interest expense, was $16 million in the third quarter and was driven by our significant cost reduction efforts. We anticipate a strong free cash flow profile again, in the fourth quarter as we continue to operate with a minimal capital budget and execute on our cost-saving initiatives.

Since our last earnings call in August, we have significantly added crude oil hedges for 2021 and 2022. Currently, we have hedged approximately 75% of our fourth quarter 2020 crude oil production at attractive pricing. In 2021, we have hedged a considerable amount of our forecasted crude oil production with a mix of swaps and collars. Our collar positions are more heavily weighted to the back half of the year, which will allow for greater upside participation in the market recovery. We intend to add to our 2021 hedge book over the coming months, and we'll begin to layer on incremental hedges in 2022 and 2023 as the market allows.

As explained during the second quarter earnings call, we monetized most of our 2021 crude oil contracts in order to capture market dislocation at that time and position the company to fully participate in the crude oil recovery moving into next year. This trade was very beneficial to the company, and we have rehedged those volumes, locking in the improved economics. Our hedging program will allow us to protect future cash flows, while also capturing potential upside in an improving commodity price environment.

As of October 30, 2020, our hedged mark-to-market value was a net asset position of $13 million. Amplify's third quarter 2020 hedge presentation contains additional details on our current positions and was posted on our website earlier today under the Investor Relations section.

Moving on to a discussion of our recent credit facility redetermination and our current liquidity position.

Since the spring of 2020 redetermination, we have reduced indebtedness in compliance with the scheduled monthly $5 million borrowing base reductions using internally generated free cash flow. As of October 30, we had total net debt of $243 million with $260 million outstanding under our revolving credit facility and $17 million of cash on hand. With the spring 2020 redetermination borrowing base reductions now concluded, Amplify expects to utilize excess cash flow for further debt reductions and additional capital for higher rate of return projects.

Amplify's fall 2020 borrowing base redetermination process is currently underway and we anticipate completing the process before the end of November. Although the borrowing base was reduced in spring 2020 as a result of market disruptions related to the ongoing COVID-19 pandemic and commodity price volatility, we anticipate that the current redetermination process will provide a result that supports our liquidity position and a solid foundation for substantial free cash flow generation.

With this in mind, I'll now turn the call over to Jason McGlynn. Jason?

Thank you, Martyn. As previously mentioned, production for the third quarter averaged approximately 27,700 BOE per day, which was flat with the prior quarter and exceeded internal expectations. This outstanding result can be attributed to strong performance across all of our asset areas and Beta royalty relief, which took effect at the beginning of the third quarter. As mentioned in our earnings release, our crude oil volumes grew by 5% quarter-over-quarter, resulting in a third quarter production mix of 39% oil, 17% NGLs and 44% natural gas.

Lease operating expenses for the third quarter were $27.6 million or $10.86 per BOE, down from $27.8 million or $11.03 per BOE for the prior quarter and considerably exceeding our internal expectations on both a total dollar basis and a per BOE basis. The reduction in lease operating expenses was due to the continuing execution of our cost-saving initiatives instituted earlier this year and production outperformance.

As we look to close out the remainder of 2020 and move into 2021, Amplify remains committed to operational excellence and efficiency, and our outstanding operating team will continue to identify and capitalize on additional cost reduction efforts.

GP&T was up this quarter to $5.3 million or $2.07 per BOE, compared to $4.7 million or $1.86 per BOE in the second quarter of 2020. This increase was primarily related to an increase in oil and gas revenues during the quarter.

Taxes and other income increased this quarter to $3.8 million or $1.48 per BOE, compared to $2.2 million or $0.87 per BOE in the second quarter. Again, this increase was primarily related to the increases in oil and gas revenue during the quarter.

G&A expense for the third quarter was $6.4 million, including approximately $0.5 million of noncash compensation and $0.3 million of nonrecurring transaction costs and bad debt expense. Excluding the noncash and nonrecurring costs, third quarter cash G&A totaled $5.6 million or $2.20 per BOE compared to $6.2 million or $2.45 per BOE in the second quarter of 2020. This reduction in reoccurring cash G&A expenses validates the company's commitment to delivering approximately $2.5 million in annualized cash G&A savings by the end of the third quarter and paved the way for achieving an annualized run rate of approximately $22 million.

That concludes our prepared statements. With that, operator, we are now ready for questions.

(Operator Instructions) And our first question is going to come from the line of Jeff Grampp, Northland.

Martyn, wanted to start on the borrowing base front. I know, obviously, you don't have a number in hand yet, but at least directionally, do you have a sense? Is flat a possibility? I imagine up's off the table, but can you be kind of flattish? Or do you have any sense of if there was that kind of magnitude? And do you think the banks are going to want kind of that forced amortization feature to be extended? Or do you think that might be able to be removed?

So obviously, we have to get through the process. But I think as far as an assumption, obviously, prices have increased since our last redetermination, and we've executed on the cost reduction initiatives that we had implemented. And so I believe that a flat result is very attainable. Guarantees, at this point, but I think a flat -- a flat borrowing base with no additional mandatory reductions is the most likely outcome at this point.

Okay. That's great to hear. On the capital side, we've seen gas kind of rallying here into the winter. I know you guys obviously have kind of a multi-commodity exposure in terms of capital flexibility. Do gas project make sense for you guys at these prices? Or just generically, maybe it would be great to get your thoughts on how you're thinking about capital deployment here beyond kind of the few million of mandatory maintenance CapEx we see from you?

Yes. So obviously, as part of our 2021 budget, we're taking a harder look at some of those gas projects. There's a mixture of operated project potential, but there's also some non-operated projects that we have a fairly significant working interest in that could be of interest to us. So we are certainly looking at those. Obviously, we're managing for free cash flow and managing, making sure that all those projects make sense and from both an IRR and payback period perspective. So we -- so certainly, they're much more on the table than they've been in the last couple of years, and that will be kind of flushed out in our budget process over the next couple of months.

Okay. Great. And last one for me just on the the CEO side of things. I know kind of you're on the interim side. Is the Board looking to kind of formalize that or has the search undergoing? Or any kind of color you can provide us on that?

Well, obviously, we've -- our primary focus for the last 6 months has just been making sure we got everything executed on the operations side. As far as I know, there's no ongoing search for this -- a different CEO. So I expect that something -- we'll review that in the coming months and going into 2021.

Our next question will come from the line of Noel Parks, Coker & Palmer.

Hope everyone's doing well down there. And just a couple of questions. You did talk -- or if you can just refresh your memory about the monetizations you did earlier in the year. But I was just looking at the updated hedge total, were there any monetizations performed in the quarter? Or were there just normal settlements?

No. There were just normal settlements during this quarter. Those hedge monetizations took place in the second quarter when the Cal '21 strip was in the mid-30s. And we felt like before the end of the year, we'd have the chance to rehedge those volumes at a much better environment. So somewhere between 42 and 45, depending on the hedges, we've rehedged those volumes, kind of locking in that gain. And so that was kind of always the idea, and we were able to execute on that during this quarter.

Great. And maybe you don't generally formally guide on what your expectations are for price realizations. But if you could just even characterize generally sort of what you're seeing or just what -- or maybe more importantly, what trends you're watching for the different products?

Yes. Obviously, in the past, we've guided to price realizations. I think, obviously, you've seen NGLs be a little bit stronger recently than they've been over the last, call it, year prior. So the realizations, relative to crude, are doing a little bit better. Gas is obviously doing better. For example, the Mid-Con region has obviously improved its netbacks as well. So by and large, I think it's improved. There are some areas that are -- we have a non-operated position in Eagle Ford, where I think the oil price has been a little bit weaker. But in the Rockies, it's been a little bit stronger. And so it's been kind of a little bit of a mixed bag.

And so I think for now, kind of the realizations from this quarter would be your best estimate for kind of a go-forward look. And hopefully, by prior to -- for our next call, we'll be implementing guidance again for 2021 and can give greater color on those questions.

Yes. Noel, the only thing I'll add there is -- this is Jason -- is there are a lot of disruption this year and a lot of movement and volatility in the commodity side. And some of our stuff out in Beta that's midway sunset, that's had a little bit of dislocation, and we'd anticipate that kind of going back to the norms as we move farther out into 2021. And in forward pricing, and there's been some of that stuff happening in the Mid-Con area, too. And as we said, we've actually had some better pricing, as Martyn mentioned, in the Rockies. So we'd anticipate that going back to more historical norms and moving forward. But I think, as Martyn said, a good proxy for Q4 is kind of where we're at right now.

Okay, great. And I believe in the past, you've talked about sort of a baseline maintenance CapEx level of just $5 million to $10 million. And we've had some -- well, gas looked pretty good, but we certainly had more disruption on oil price in just the last couple of months. And if we were -- if we sort of [carry the card] with COVID and things start stabilizing or improving a little bit for oil, we have the weak demand in contango. So we at least have that little bit of encouragement in the strip.

Do you have any sense of, at a higher price, whether there are any sorts of projects that, sort of low-hanging fruit, that might head to the front burner if, say, a quarter from now, we were sort of closing back in on 50, sort of where we were headed sort of like in late summer?

Yes. I'll address that. Obviously, we have a number of workover opportunities across the company, especially in Oklahoma. As we've talked about those -- some of those ESP projects might make more sense at 50 than they do at 40, bringing some of that production that's basically just off-line right now, bringing that back online. Now those are kind of low-hanging fruit in the right economic environment.

Obviously, at the beginning of this year, we talked about developing Beta, and so that's something that if we see some continued price improvement through 2021, that might be we'll revisit those projects. And then obviously, we already talked about the fact that gas is a lot more attractive now, and that applies to both East Texas and some Oklahoma -- small Oklahoma projects potentially as well. So we have some opportunities, but we're also, like I said, going to be very conscious of free cash flow in 2021, while it's -- we're still in this depressed environment. But if we can start to get a little bit of clearance in that 50 -- especially in that 50 and above level, then maybe you do start to moderately increase activity levels at that point.

Great. And as an example, for those workover opportunities, especially the ESP substitutions, what's roughly the payback time on a project like that?

Typically, we look at high-grading the ones that are a year or less. And so there's several of those still in inventory right now. And obviously, as the price, both the gas price and the oil price improves, a greater number of those kind of move up the ranking. And so those are the kind of things that we're looking at as the market continues to recover because they are a mixture of gas, oil and NGLs, obviously. And so we're cognizant of all 3 streams there and the impact that has on the economics.

At this time, we have no further questions.

All right. Thank you. So this year has been challenging for the industry and our company. While the ongoing COVID-19 pandemic has continued to impact demand and prices have been slow to recover, the organization has demonstrated its resiliency and ability to adapt to the current environment. I cannot express my appreciation enough to the company's employees for their outstanding efforts and continued dedication.

I would also like to thank our stakeholders for their continued support as we persevere through these difficult times. With strong free cash flow expected for the remainder of 2020 and 2021, we look forward to continuing to execute for all of our stakeholders and preparing for future opportunities. Thank you for joining us today. And as always, please do not hesitate to reach out to us with any additional questions.

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