Amplify Energy Corp.

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. 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 25th. by dialing 855-859-2056 and entering conference ID number 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 Martin Wilshire, 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. 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 at www.amplifyenergy.com. With that, I'll now turn the call over to Martin.

Thank you, Jason. During the call, I will provide comments on our fourth quarter operating results, year-end 2020 approved 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 work over activity during the quarter. Fourth quarter adjusted EBITDA was approximately $21.9 million, which was above internal projections. This represents 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 work over activity. Amplify's full-year capital spending for 2020 was approximately $29 million, with only $14 million spent after the first quarter. The reduced capex demonstrates the flexibility of managing a mature, low-declined 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 reductions since inception. Earlier today, we announced Amplify's 2020 year-end approved reserves estimates of approximately 114 MMBOE with a PV10 value of $298 million based on SEC pricing of $39.57 per barrel for crude oil and $1.99 per mm BTU 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 approved reserves was approximately 41% crude oil, 19% natural gas liquids, and 40% natural gas, with approximately 85% of the approved reserves classified as proof 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 strict pricing as of March 1, 2021, the company's year-end 2020 proved reserves increased to approximately 160 MMBOE with a PV10 of $778 million, of which 118 MMBOE and $594 million of PV10 value is classified as proved developed reserves. Additionally, we have now provided our guidance expectations for full year 2021. Our four-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 mature 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 to $39 million, which includes approximately $16 million for development projects at Beta and in the Eagleford, and approximately $18 million in facilities and capital work over projects. Amplified development capital will primarily be deployed at our Beta field, where we budget approximately $10 million to commence a limited phase development program to enhance the asset with minimal incremental operating costs. The Beta reservoir features six separate stacked 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 case-toll recompletion and two sidetracks of existing wells that will target longer completion intervals in Beta's most prolific reservoir zones. We view the phase nature of the program as a means of de-risking a more expansive, 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 is also important to note that at this time, we do not anticipate any impact to 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 ducts in the Eagleford. 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 ESB 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 Barrel, 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'll now turn the call over to Jason.

Thank you, Martin. 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 the 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 total $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 the timing of minor year-end adjustments. David Wiltshire- Capital spending in the fourth quarter with approximately $2.2 million and below the projection provided during our last earnings call. David Wiltshire- For the full year 2020 amplify spent approximately $29.2 million in capital expenditures. David Wiltshire- Primarily focused on facility maintenance projects essential to the equipment integrity and operational efficiency high rate of return work over projects and non operated drilling and completion activity in the equal for. 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 Erie. As mentioned in our release this morning, our Oklahoma, East Texas, and Eagleford assets experienced production interruptions due to the extreme cold, ice, and snow produced by Winter Storm Erie. Production levels will return 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 amplified 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 facility 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 Martin previously mentioned, our full year 2021 average daily production forecast ranges from 23,000 to 25,000 VOE per day, and our CapEx forecast for the year is $28 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 realization, GP&T cost, and cash interest expense weren't 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've 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.

At this time, if you would like to ask an audio question, you may do so by pressing star and the number one on your telephone keypad. Again, that is star one. We'll pause for just a moment. The first question will come from the line of John White with Roth Capital.

Good morning. Congratulations. Nice results. On the shelf registration, I'm modeling 2021 with significant free cash flow and debt reduction. I just want to confirm again, the shelf registration is in order to be prepared for any acquisition opportunities, uh, you, 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.

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

Yeah, I think there's been a number of packages that have came out over the last couple of months, and I think one thing that differentiates it from what we've seen last year is the quality of the packages that are coming up is a little bit better than what we've seen recently. So that gives us a lot of – we're very excited to anticipate seeing some more of that continuing throughout 2021.

Yeah, and John, just to continue, going into 2020, we were certainly looking at additional opportunities to add scale and through mergers or acquisitions. And as things return to normal in 2021, that's certainly something that we're looking to continue that process. And obviously the S3 is just another way for us to potentially get there as needed.

Okay. Well, thanks for that confirmation. And my last on beta, did you mention, did you give a number of new wells that'll be drilled or a well count?

So in 2021 we're planning around, it's basically three wells and they're primarily extensions of existing wells that are going to be drilled a little differently to capture a little bit more of the best zones. So it's, we're starting, we have a program that starts in 21 and continues into 2022. But like we said on the call, there's not a big impact in production in 2021. Obviously, as you start a capital program, there's always a lag between your spending the money and receiving kind of the rewards of the program. So as this is a second half 21 weighted program, you're going to see more of the production uplift in 2022. So like I said, that's probably one little disconnect between where you see the capital spend and where you see the production and EBITDA impacts.

All right. Well, thanks very much for all that. Thanks, John.

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

Hey, good morning. I was just curious, the inspection, in aggregate, how much will that cost be? And I was wondering, will you sort of break those separate so we can tell they're like a non-occurring item?

Yeah, so every 10 years you are required to do stage three, and we're actually doing stage two and stage three inspections this year on our platforms. We're not anticipating any issues, obviously, but they do run between, call it three and a half and four million dollars, which is why we alluded to 50 cents per BOE of column. I don't want to call them non-recurring costs because they recur just very infrequently, call it every 10 years. So that's why we broke it out separately. That is costs will incur around between the second and third quarters of this year.

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

Our primary partner in Eagleford is Murphy. We've read their materials and obviously had conversations, and we're not aware of any additional pickup in activity yet from them, so we have modeled accordingly. which is primarily just the completion of the ducts that we drilled last year around the end of the first quarter and into the second quarter. So that's how we've modeled it so far. Obviously, they can change plans later in the year if they so choose, but as of right now, we're not aware of anything. I think from an activity level and operated side, obviously, we do have some flexibility in some of our areas, but primarily we're going to be focused on that beta development plan and And, you know, we do have some offline wells in Oklahoma where we could potentially pick up some additional production if prices hold at these kind of levels. The economics are pretty strong.

Great. Thanks.

Again, to ask an audio question, you may do so by pressing star and the number one on your telephone keypad. We do have a question from the line of Mark Kaufman with Eagle Rock Capital.

Hey, good morning. How are you? Good morning, Mark. I just have a few questions specifically around differentials and also NGL pricing currently. Last year in 2020, they widened down 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 to NYMEX, Henry. It's to Henry Hub pricing. But yeah, we do expect a little bit of contraction. I mean, you had some basis differential blowout over the last number of years. We do have a portion of that hedge for 2021, but that is something that has been contracting in the back half of 20 and into 2021. So we do expect a little bit better realizations than what we saw last year.

Yeah, 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 up in Oklahoma and 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 is based on actually what we're seeing, not just what we're projecting. So it's been a much more improved differential market since some of the stuff that you saw earlier in 2020.

Yeah, 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 to 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. Thank you on that. In a sense, to offset the negative differential that you're seeing in natural gas right now. It's just math. I'm just taking one and the other, a third of one, two-thirds 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 type of time frame.

Are you seeing, not necessarily you, but exporting out of the eastern producers? Or are you also seeing some of that, you know, or just plain use down in East Texas and Oklahoma area?

Most of our, you know, we obviously sell to the plants and obviously where they take the NGLs from there obviously depends on their own economics. So, we obviously have the, you know, the gathering and processing agreements at the plant level. So, not sure exactly it downstream, but you have seen obviously propane has been, for example, very, very strong as you've had exports in addition to strong usage through the winter. Storage levels are extremely low, and so that's an area where without all the associated gas and any northeast growth, then propane levels should stay strong, and obviously that drives the butanes as well. Ethane is obviously more correlated with gas, and C5 with oil. So the propane is kind of the key for our NGL barrel, and that's why Oklahoma's been fairly strong.

Okay. Can I ask you another question about beta? Sure. And so that is priced, again, it's what I want to say, a blend, a blend WTI and Brent. So have you been seeing, you know, better pricing, what you're looking at, let's say in 2022, or even what's not edged this year?

Yeah, I'll say that, you know, typically, you know, going into 2020, you know, it moves in correlation with Brent, but it's certainly a discount to Brent. It doesn't trade at Brent. It's an index called Midway Sunset. And so it's kind of correlated with Brent. And so lately, it's been trading much more closer to in line with WTI. It was far below WTI for most of last year. So it has gotten stronger. As you've seen, a lot of the local areas have gotten stronger on differentials during the year. So it's been a, like I said, it's gotten strong pricing to go with a lot of the other advantages of low royalty rates, very low incremental operating costs. You know, the rigs are already on the platforms. So it's got very strong operating leverage to bringing on additional production in that area. And that's why we've targeted it, along with the fact that there's a substantial amount of additional oil in place. And we've had a good amount of time to study this and feel very confident in the program. And we are leaning into the program by doing some kind of lower-cost wells first. But we're very excited about the potential of that program. And 21 is just a starting point. Obviously, we plan to continue from there.

So, so this next question, I think ties into that question, uh, about how your, your cadence for capital expenditures this year. Um, so the average for the year, you know, the, the quarterly, uh, uh, excuse me, the, the average daily production, is there going to be a cadence in the quarter? Does it decline all year? Does it decline earlier in the year? The client starts to change as you bring on, uh, some data. And does that need to start to look at maybe a flatter production, let's say out in 2022 or toward the end of this year?

Yeah, 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 Barrel. So those are two events that, you know, we always plan in to all of our production forecasts. But as we get into the second half of the year, you know, you start to you'll have the impact of some of the Eagleford development. You'll have the impact of some of the beta wells starting to come online kind of late third quarter, probably more like middle of 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 margins free cash flow, unsustainable 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, what your plans are? I think we've discussed this before, you know, and then planning your hedge book for 2022.

That's correct. I mean, we just outlined the numbers. We're at about 65% hedged on oil as we move into that. Obviously, we understand what the production forecasts look 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. Appreciate it. Nice job, gentlemen. Look forward to... Actually, I have one other question. How come you put the March number out for the bank loan and the cash outstanding? And so I don't have the year-end to actually see what the change in cash flow you generated for the first two months. It just is what it is.

Yeah, 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. Okay. I think the numbers were, we probably cashed 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 the comments.

Yeah, it looked pretty good. That's why I was asking the question. Thanks, Mark. You're welcome.

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

Yeah, 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 kind of all over the place. There's a lot within our operating areas and outside of our operating areas as well. I think just expanding a little bit is we're virtually agnostic to geographic where we can add additional production. It's more about value and what we can get on a creative to the enterprise basis. Naturally, we'd like to focus in some areas where we can have operating synergies to drive, you know, additional value to come our way for the business. But I'd say as far as packages and activity from M&A, it's kind of been widespread all over the major operating basins.

I appreciate that. Thanks for taking my follow-up. Thanks, John.

We are showing no further audio questions at this time.

All right. Thank you. Just to conclude, we are really encouraged by the overall improvement in the market conditions, and we expect that 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.