Amplify Energy Corp. Q4 FY2020 Earnings Call

Welcome to Amplify Energy's Fourth 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. Today's call is being recorded. A replay of the call will be accessible until Thursday, March 25, by dialing 855-859-2056, and entering conference ID# 3731609, 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 2020. 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 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 we expect to file later today. Also, non-GAAP financial measures may be disclosed during this call. Reconciliation of those measures to comparable GAAP measures may be found in our earnings release or on our website. With that, I'll now turn the call over to Martyn.

Thank you, Jason. During the call, I will provide comments on our fourth quarter operating results, year-end 2020 proved reserves, and guidance expectations for full year 2021. I'll then turn the call over to Jason to provide additional details on our financial performance, 2021 guidance, hedging program, liquidity position, and balance sheet. Following our prepared remarks, we will take questions, and I will conclude with closing remarks. Production for the fourth quarter exceeded internal forecasts, averaging approximately 26,300 BOE per day, a 5% decrease from 27,700 BOE per day in the third quarter of 2020. The decrease in production was primarily the result of projected natural decline and reduced capital workover activity during the quarter. Fourth quarter adjusted EBITDA was approximately $21.9 million, which is above internal projections. This represented a decline of $2.9 million quarter-over-quarter and was principally associated with production declines, partially offset by improved operating margins due to higher commodity prices during the quarter. Capital spending for the fourth quarter was approximately $2.2 million, a decrease of $2.8 million from $5 million in the third quarter and was largely attributable to reduced capital workover activity. Amplify's full year capital spending for 2020 was approximately $29 million, with only $14 million spent after the first quarter that reduced CapEx demonstrates the flexibility of managing a mature low-decline asset through commodity cycles. Free cash flow, defined as adjusted EBITDA, less CapEx and cash interest expense, was approximately $16 million in the fourth quarter and remained flat from the prior quarter despite the reduced production. Amplify's focus on maintaining a strong free cash flow profile was realized through the prudent deployment of capital to the highest return projects, relentless attention to operating efficiencies, and commitment to controlling costs. As a result, the company achieved its strongest year in operating cost reduction since inception. Earlier today, we announced Amplify's 2020 year-end proved reserve estimates of approximately 114 MMboe with a PV-10 value of $298 million based on SEC pricing of $39.57 per barrel for crude oil and $1.99 per MMBtu for natural gas. Compared to year-end 2019, SEC pricing for crude oil was down 29% and natural gas pricing was down 23%. The product mix for our proved reserves was approximately 41% crude oil, 19% natural gas liquids, and 40% natural gas, with approximately 85% of the proved reserves classified as proved developed. While year-end 2020 SEC reserve pricing is a stark reminder of the dramatic impact COVID-19 had on commodity prices in 2020, it does not reflect the value of our reserves in the current commodity pricing environment. Utilizing strip pricing as of March 1, 2021, the company's year-end 2020 proved reserves increased to approximately 160 MBOE with a PV-10 of $778 million, of which 118 MMBoe and $594 million of PV-10 value are classified as proved developed reserves. Additionally, we have now provided our guidance expectations for full year 2021. Our full year 2021 average daily production forecast ranges from 23,000 to 25,000 BOE per day. As a result of the low-decline rates of our material oil properties, we anticipate that our product mix will continue to become increasingly more oil-weighted over time, and we anticipate our production in 2021 to be approximately 42% oil, 16% NGLs, and 42% natural gas. Our CapEx forecast for the year is $28 million to $39 million, which includes approximately $16 million for development projects at Beta and in the Eagle Ford, and approximately $18 million in facilities and capital workover projects, and provides development capital primarily to be deployed at our Beta field, where we budgeted approximately $10 million to commence a limited phase development program to enhance the asset with incremental operating costs. The Beta reservoir features six separate stack zones estimated to hold approximately 1 billion barrels of high-density original oil in place with only 11% recovered to date. The initial phase of our development program includes a cased hole recompletion and two sidetracks of existing wells that will target longer completion intervals in Beta's most prolific reservoir zones. We view the phased nature of the program as a means of derisking a more expensive development program in the future that has the potential to unlock substantial economic value while also bolstering the company's free cash flow profile and increasing margins. The development work at Beta is scheduled to begin in the second half of 2021, with the full impact of the program largely realized in our 2022 results. It's also important to note that at this time, we do not anticipate any impact on our short-term or long-term development plans at Beta based on the current regulatory environment. In addition to Beta, we expect to incur approximately $6 million of additional development capital to participate in the completion of approximately 1.2 net non-operated DUCs in the Eagle Ford. Roughly $3 million of the budgeted capital was prepaid in the fourth quarter of 2020, but will be reflected in our 2021 financials. The remainder of our capital budget will be deployed across all of our asset areas and will focus on our strongest return projects. We anticipate spending approximately $8 million in Oklahoma for additional 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 $10 million in 2021 for facility work and capital workovers at Bairoil, Beta, and East Texas. Our 2020 results demonstrate the sustainable value of our mature PDP weighted operating platform; the company's operational adaptability and efficiency coupled with a robust hedging program led to strong free cash flow generation even in a volatile commodity price environment. With an improving market outlook, we will maintain our commitment to improving our balance sheet and driving equity value for our stakeholders. To that end, we intend to file a shelf registration statement in order to access the capital markets and provide additional flexibility when evaluating potential transaction opportunities as they arise. With this in mind, I will now turn the call over to Jason.

Thank you, Martyn. I'll first provide details on the company's fourth quarter production and expenses. I'll then provide an update on our balance sheet and finish up with a discussion on our 2021 guidance numbers and hedge book. As previously mentioned, production for the fourth quarter averaged approximately 26,300 BOE per day with a production mix of approximately 40% oil, 17% NGLs, and 43% gas. Notably, our oil production mix of 40% in the fourth quarter is an increase of approximately 11% from 36% in the first quarter of 2020. This is a favorable shift, and we expect our production mix to continue on this trend moving forward. Lease operating expenses for the fourth quarter totaled $28.5 million or $11.77 per BOE, down from $35.7 million or $12.98 per BOE for the same period in 2019 and were in line with our projections. LOE reductions from prior periods held relatively steady throughout the fourth quarter of 2020, and the majority are expected to continue through 2021. GP&T this quarter was $5.5 million or $2.29 per BOE and was relatively flat with $5.3 million or $2.07 per BOE in the third quarter. Taxes and other income decreased this quarter to $3 million or $1.24 per BOE compared to $3.8 million or $1.48 per BOE in the third quarter. This decrease was mainly associated with lower ad valorem tax rates. Fourth quarter cash G&A totaled $5.8 million or $2.38 per BOE compared to $5.6 million or $2.20 per BOE in the third quarter of 2020. The increase was largely attributed to timing of minor year-end adjustments. Capital spending in the fourth quarter was approximately $2.2 million and below the projection provided during our last earnings call. For the full year 2020, Amplify spent approximately $29.2 million in capital expenditures, primarily focused on facility maintenance projects essential to the equipment integrity and operational efficiency, high rate of return workover projects, and non-operated drilling and completion activity in the Eagle Ford. Our mature asset base requires minimal CapEx to maintain free cash flow at lower prices and presents attractive economics at and above the current strip, allowing us the flexibility to adapt to changing market conditions. I would now like to provide a quick update on Winter Storm Uri. As mentioned in our release this morning, our Oklahoma, East Texas and Eagle Ford assets experienced production interruptions due to the extreme cold, ice, and snow produced by Winter Storm Uri. Production levels returned to pre-storm levels within 10 days, and full production targets are within approximately 200 BOE per day of original estimates. The swift return of our production is a testament to the top-tier operating efficiency of our field staff. On to the balance sheet. On November 18, 2020, we successfully completed our fall borrowing base redetermination and reaffirmed the company's borrowing base of $260 million. The fall redetermination was significant in supporting Amplify's liquidity and improving our leverage profile moving forward. As of March 1, 2021, our net debt was approximately $228 million, consisting of $250 million outstanding under our revolving credit and $22 million of cash on hand. In 2021, we intend to continue allocating the majority of our free cash flow to improving our balance sheet and reducing our total debt outstanding. We anticipate completing the spring 2021 redetermination process before the end of May. Moving to guidance. As Martyn previously mentioned, our full year 2021 average daily production forecast ranges from 23,000 to 25,000 BOE per day; and our CapEx forecast for the year is $28 million to $39 million. On the expense side, we are forecasting LOE per BOE range of $12.50 to $14.50. This range is above our fourth quarter LOE of $11.77 per BOE, due primarily to the production forecast during 2021 and approximately $0.50 per BOE for statutorily required inspections of Beta, which will not be required for another 10 years. Lastly, we anticipate recurring cash G&A expenses to range between $2.45 and $2.75 per BOE for the year. Additional details on commodity price realizations, GP&T cost and cash interest expense were provided in our earnings release this morning and can be found in the latest investor presentation currently available on our website. Now to our hedge book. Since our last earnings call in November, we have added substantial oil and gas hedges for 2021 and 2022. Across commodities, we're approximately 84% hedged in 2021 and 58% hedged in 2022. Currently, our crude oil production is 90% hedged for 2021 and 65% hedged for 2022. We continue to monitor the market for opportunities to layer on incremental hedges for the next several years. Amplify's March 2021 hedge presentation contains additional details regarding our current positions and was posted to our website earlier today under the Investor Relations section. That concludes our prepared remarks. Operator, we are now ready for questions.

The first question will come from John White with ROTH Capital.

Nice results. On the shelf registration, I'm modeling 2021 with significant free cash flow and debt reduction. So I just want to confirm again, the shelf registration is in order to be prepared for any acquisition opportunities you might become aware of?

Yes. John, that's exactly right. The S3 is simply a housekeeping item to put us in position to quickly move on accretive transactions should the opportunities arise.

Yes. And I get the impression from the calls I've been on so far that seller initiatives are picking up a little bit of activity. Are you seeing that?

Yes, I think there have been several packages released in the past few months. One thing that stands out compared to last year is that the quality of these packages seems to be better than what we've seen lately. This really excites us, and we look forward to seeing more of this throughout 2021.

Yes. And John, just to continue, going into 2020, we were certainly looking at additional opportunities to add scale through mergers or acquisitions. As things return to normal in 2021, that's certainly something that we're continuing to examine. The S3 is just another way for us to potentially achieve that as needed.

Okay. And my last question is, did you provide a number of new wells that will be drilled or a well count?

In 2021, we plan to drill three wells, primarily extensions of existing ones, using a different approach to capture more of the optimal zones. The program begins in 2021 and continues into 2022. However, there won't be a significant production impact in 2021. When starting a capital program, there's typically a delay between spending and realizing the benefits. Since this phased development program is focused on the latter half of 2021, more of the production increase will be seen in 2022. This highlights the disconnect between capital spending and the related production and EBITDA effects.

Our next question will come from the line of Noel Parks with Touhy Brothers.

I was curious about the inspection and what the total cost will be. Could you break that down so we can identify if there is a non-recurring item?

Yes. So every 10 years, you are required to do stage 3 inspections, and we're actually doing stage 2 and stage 3 inspections this year on our platforms. We're not anticipating any issues, obviously, but they do run between $3.5 million and $4 million, which is why we alluded to $0.50 per BOE of, call them non-recurring costs because they recur just very infrequently, about every 10 years. So that's why we broke it out separately. That is a cost we'll incur around between the second and third quarters of this year.

Great. And my other question is on the non-operated side. Now we're seeing stronger commodity prices and even the gas strip isn't looking too bad. But I was wondering, on the operating side, is there a chance of more activity by those partners this year than you were thinking of a quarter ago?

Our main partner in the Eagle Ford is Murphy. We've reviewed their materials and have had discussions, but we are not aware of any increase in their activity at this time. Therefore, we have planned based on the completion of the DUCs we drilled last year, which we expect to finalize by the end of the first quarter and into the second quarter. This is our current plan, but it may change later in the year if they decide to adjust their strategy. At the moment, we have no updates on this front. In terms of our operated activities, we do have some flexibility in certain areas, but our main focus will be on the Beta development plan. We have some offline wells in Oklahoma that could potentially enhance production if prices remain stable, as the economics are quite favorable.

We do have a question from Mark Kaufman with Eagle Rock Capital.

I just have a few questions. Specifically around differentials and also NGL pricing currently. Last year, in 2020, they widened out on natural gas. And it seems you're anticipating a tightening somewhat in natural gas. The idea about a 20% discount to the NYMEX or the Henry Hub?

It's linked to NYMEX and Henry Hub pricing. However, we do anticipate a slight contraction. There was a significant basis differential increase over the past few years. We have a portion of that hedge for 2021, but it has been contracting in the second half of 2020 and into 2021. We expect a slightly better realization compared to what we experienced last year.

Yes. And I'll add on the NGL side. We have NGLs primarily from Oklahoma and East Texas. Oklahoma has a significant amount of propane. It's been realizing fairly strong Oklahoma, stronger than East Texas. So the 38% to 42% that you're seeing between kind of on a blended basis in our guidance is a little strong in Oklahoma, a little weaker in East Texas. But those are largely unhedged, and we feel like the market there has been realizing much stronger on an actual spot basis than it looks on the forward curves. And so we've left that relatively open to take advantage of that market. But like I said, this has been based on actually what we're seeing, not just what we're projecting. So it has been a much more improved differential market since some of the conditions that you saw earlier in 2020.

Yes. I mean you have it hedged right now or at least a small amount hedged at $24 or $4 McF equivalent. And so I guess you're pointing toward that you're probably going to continue that; you expect, or at least you're currently seeing that on a blended basis, or maybe better than $4 per Mcf?

That's correct.

Okay. Well, that's significant. In a sense, to offset the negative differential that you're seeing in natural gas right now. It's just math. Just taking one in the other, 1/3 of one, 2/3 of the other, and it certainly makes up a lot of ground for you.

Absolutely. We're pretty excited with how NGL pricing realizations have moved. I mean, this is the strongest pricing we've seen since back in the '14-'15 timeframe.

Are you seeing any exports from the eastern producers? Or are you also noticing some of that, or is it just localized in the East Texas and Oklahoma area?

Most of our sales are directed to the plants, and the allocation of NGLs from there is influenced by our own economics. We have gathering and processing agreements at the plant level, so the downstream transport details are still uncertain. However, propane has exhibited strong performance due to exports and high winter usage. Storage levels are quite low, and without the associated gas and any growth in the northeast, propane levels are expected to remain robust. This strength in propane also impacts butanes. Ethane tends to be more closely tied to gas markets, while C5 is associated with oil. Therefore, propane is critical for our NGL production, and that's why the Oklahoma region has performed relatively well.

Okay. Can I ask another question about Beta?

Sure.

And so that is priced, I don't want to say a blend, a blend of WTI and Brent. Have you been seeing better pricing compared to what you saw in 2022 or even for what is not hedged this year?

Yes. Typically, as we approached 2020, it was correlated with Brent, but it trades at a discount to Brent. The index is called Midway Sunset, and while it's generally connected to Brent, it has been trading much closer to WTI recently. It was significantly below WTI for most of last year, but it has strengthened as local areas have shown improvement in differentials this year. The pricing has been strong, supported by low royalty rates and minimal incremental operating costs since the rigs are already in place. This gives us great operating leverage for increasing production in that region. That's one reason we've focused on it, along with the significant additional oil available and our extensive analysis which gives us confidence in the program. We're starting with lower-cost wells, and we are very optimistic about the program's potential. 2021 is just the beginning, and we plan to build on this moving forward.

So this next question relates to your capital expenditures cadence for this year. What is the average daily production for the year? Will there be a consistent trend in production throughout the quarter? Is there a decline expected for the entire year, or will it decrease earlier? How will the introduction of some Beta affect this? Should we anticipate a more stable production rate moving into 2022 or towards the end of this year?

Yes. It should grow a little bit. So obviously, February is going to have the impact of Winter Storm Uri. And then in May, we do have our annual turnaround at Bairoil. So those are two events that we always plan into all of our production forecast. But as we get into the second half of the year, you start to have the impact of some of the Eagle Ford development. You'll have the impact of some of the Beta wells coming online kind of late third quarter, probably more like in the middle of the fourth quarter. And so there's just not a huge impact on overall production levels. But obviously, it's impactful from the oil-to-oil mix perspective. And so it's driving margins. And as you've heard us probably say in the past, we're far more focused on driving free cash flow and sustainable free cash flow than we are on an absolute production target level. And so that's why you'll see our mix continue to get oilier as we focus on those projects that have the highest margins.

So now does this also give you an opportunity, given your plans, to discuss your hedge book for 2022?

That's correct. I mean we just aligned the numbers where we're at about 65% hedged on oil as we move into that. Obviously, we understand what the production forecast looks like from the activity we have planned out. But yes, as we kind of roll into '22 into '23, we'll factor all those decisions and look at the market to opportunistically add additional hedges.

Okay, I appreciate it. I actually have one more question. Why did you release the March figures for the bank loan and the cash outstanding? I don't have the year-end numbers to see what might change in the cash flow generated during the first two months. It seems to be set as is.

Yes. We try to give the most up-to-date information, but obviously, all that information is in the K that's coming out this afternoon. So you'll have all that. I think, the numbers were we probably cash flow a little more in the first two months of this year based on the fact there were some prepays going into the end of last year, which we alluded to in comments.

The next question will come from the line of John White with ROTH Capital.

Yes. I just wanted to follow up on M&A again. Is there a particular region, say, the Rockies or the Mid-Continent or East Texas where you're seeing more seller activity than compared to other areas? And if you don't want to provide that detail, I certainly understand.

No. We're actually seeing activity all over the place. There’s a lot happening within our operating areas and outside of them as well. Expanding a bit further, we’re essentially indifferent to geography when it comes to adding production; it’s more about value and how it benefits the enterprise. Naturally, we want to concentrate on areas where we can achieve operational synergies to create additional value for the business. However, as for the off packages and M&A activity, it has been widespread across the major operating basins.

We are showing no further audio questions at this time.

All right. Just to conclude, we are really encouraged by the overall improvement in the market conditions. We expected the lasting and transformative steps we took last year to improve profitability will benefit us greatly in 2020 and beyond. I want to express my appreciation to the company's employees for their outstanding efforts and dedication over the last 12 months, and I'd also like to thank our stakeholders for their continued support. With the strong free cash flow we'll be generating in 2021 and beyond, we really look forward to leveraging these strategic advantages and executing on our value-driving initiatives. Thank you for joining us today. And as always, please don't hesitate to reach out if you have any additional questions.

This does conclude today's conference call. We thank you for your participation and ask that you please disconnect your line.