Alpha Metallurgical Resources Inc (CTRA) — Q2 2020 Transcript

Thank you, Allison, and good morning to all. Thank you for joining us today for Cabot's Second Quarter 2020 Earnings Call. As a reminder, on this call, we will make forward-looking statements based on our current expectations. Additionally, some of our comments will reference non-GAAP financial measures. Forward-looking statements and other disclaimers, as well as reconciliations to the most directly comparable GAAP financial measures, were provided in yesterday’s earnings release. Despite the ongoing global pandemic's impact on natural gas demand during the second quarter, which contributed to the lowest average quarterly NYMEX price since the third quarter of 1995, Cabot was still able to generate positive net income of $30.4 million or $0.08 per share. These results demonstrate our uniquely advantaged low-cost structure that we have continued to improve upon year-after-year, allowing us to deliver profitability and positive returns on capital even at the very trough of the natural gas price cycle, which is where we believe we are today. While we are seeing green shoots emerging in the natural gas market, which I will get into in more detail later in the call, I want to commend our team for delivering another profitable quarter in the face of the recent headwinds across our industry. Operationally, our team delivered another strong quarter with our daily production of 2.229 Bcf per day, exceeding the high end of our guidance range. Our realized prices before the impact of derivatives represent a $0.30 differential to NYMEX, which is in line with the low end of our full-year guidance range and is a significant improvement relative to a $0.44 differential in the prior year comparable period. Additionally, all of our operating expenses were in line with or below our guidance ranges for the quarter, demonstrating our continued focus on cost control. In the second quarter, we generated our first quarterly free cash flow deficit since the second quarter of 2018, but it's only our second free cash flow deficit in the last 17 quarters, given the historically low natural gas price environment during the first half of this year, in addition to the combination of our first half weighted capital program and a second half weighted production profile. Our plan for 2020 was expected to generate a slight free cash flow deficit during the first six months of the year before turning to a free cash flow positive program in the second half of the year. Ultimately, at the current strip, we still expect our capital program for the year to be fully funded within cash flow and to generate enough free cash flow to cover the majority of our regular dividend. Our balance sheet remains exceptionally strong with a net debt to trailing 12 months EBITDAX ratio of 1.2 times at the end of the quarter. Subsequent to the quarter-end, we used cash on the balance sheet to repay our $87 million tranche of senior notes, which matured this month. It is important to note that while we have seen a moderate expansion in our leverage metrics this year as a result of trough natural gas prices, we anticipate a significant compression in our leverage ratio next year at the current strip. This compression is driven not only by the expectation for higher EBITDAX resulting from improved price realizations, but also from lower absolute debt levels as we continue to pay down our near-term maturities with free cash flow. In yesterday's release, we reaffirmed our full-year production guidance range of 2.35 to 2.375 Bcf per day, with the midpoint of the range implying flat production levels year-over-year. Additionally, we have reaffirmed our capital program of $575 million. We also initiated our third quarter production guidance range of 2.4 to 2.45 Bcf per day, which represents a 9% sequential increase in daily production. The midpoint of our guidance range for the third quarter and full year imply that production volumes in the fourth quarter will be roughly flat to the fourth quarter of last year. On the capital side, we expect spending to sequentially decline in both the third and fourth quarters, driven by a reduction in our completion activity during the second half of the year. The macro outlook for natural gas markets is obviously on everyone’s mind, especially given the stark contrast between the current market conditions and where we believe these dynamics could be during the winter withdrawal season. On the demand side, while LNG exports have continued to disappoint this summer, we believe that July and August will likely mark the trough for the export levels, resulting in a gradual improvement in LNG utilization rates beginning in the latter part of the third quarter as the U.S. experiences fewer cargo cancellations. Our base case expectation is that as we move into the winter, higher global gas prices will put U.S. LNG back in the money, leading to significant improvements in utilization rates and a corresponding increase in export-related demand for natural gas. While we anticipate some reduction in power burn this winter due to decreased coal-to-gas switching, we would expect stronger residential and commercial demand year-over-year, assuming normal weather, which should offset any power-related demand loss. On the supply side, we continue to see the potential for over 6 Bcf per day reduction in production year-over-year this winter, driven not only by the sizable activity cuts in natural gas-focused basins, which we think is good, but also from steeper cuts in oil-focused basins, resulting in the expectation for continued structural declines in associated gas production. Given the ongoing focus across the industry on capital discipline, including the prioritization of capital allocation on debt reduction and return of capital to shareholders over growth, we believe any future recovery in natural gas supply will be much slower than in prior cycles. Ultimately, the market will need to see higher prices to either incentivize more production or to disincentivize LNG exports and economic coal-to-gas switching. While there are certainly risks to this thesis, we remain cautiously optimistic about the natural gas market heading into this winter. We remain acutely focused on executing a risk management strategy for 2021 that optimistically locks in hedges to protect against potential downside risk, while also remaining exposed to potentially one of the most favorable setups we have seen for the commodity in years. While we have yet to formulate official plans for 2021, in our release yesterday, we highlighted that based on 2021 NYMEX price assumptions of $2.75 per Mmbtu, which is roughly in line with current futures, we can deliver similar production levels as 2021 from a modestly lower capital program, while delivering a free cash flow yield of approximately 8% and a return on capital employed between 19% and 20%. As we disclosed previously, every $0.10 improvement in NYMEX natural gas price is expected to increase our 2021 free cash flow by approximately $55 million, highlighting the upside potential if the natural gas market does reach a point of inflection this winter. As we anticipate a significant expansion in free cash flow in 2021, we remain committed to disciplined capital allocation with a focus on balancing the deployment of our free cash flow next year between returning capital to shareholders and repayment of our $188 million of senior notes maturing in 2021. Our capital return focus will be grounded in our base quarterly dividend of $0.10 per share or $0.40 annually and further supplemented by potential returns of capital, including special dividends and/or share repurchases. While 2020 may ultimately deliver the lowest average NYMEX price on record since 1995, I am proud of Cabot's resiliency, highlighted by our ability to deliver positive free cash flow and positive corporate returns while maintaining a strong balance sheet even in the trough of the commodity price cycle. We will continue to execute, deliver on our plans for this year, which was formalized in February before the widespread impacts of the global pandemic, and we remain optimistic about the potential for an inflection in natural gas markets this winter and the corresponding expansion in our free cash flow, return on capital employed, and return of capital to shareholders in 2021. And Allison, with that comment, I will be more than happy to answer any questions.

Yeah. Good morning, Dan. I was wondering if you could give us a little bit more color around your thoughts on modestly lower CapEx for 2021. Maybe give us a little bit of thoughts on that.

Well, we have indicated that our 2020 program was front-loaded, the remainder of 2020, we're not going to spend as much capital. We're also in the midst of negotiations with rigs and frack crews and looking at the efficiencies we've developed in our program operationally and what we're seeing and what we think will occur with our execution contracts in the 2021 program. We think we will see that modest reduction in that program.

Great.

Yes, if you wanted a ballpark 5% to 10% as a number right now might be a useful number.

Got it. So, something maybe in this $540 million type range, something like that?

Yes, that would seem reasonable.

Got it. I did want to maybe see if you could elaborate on some of the outlook comments on 2021. Obviously, assuming a $275 million strip, you cited an 8% free cash flow yield, which would suggest, on our math, call it $580 million in free cash flow. Your annual dividends about $160 million. I think there's a desire of the company to return at least 50% of free cash flow to shareholders. So, that would suggest maybe another $130 million, but just maybe want to get your thoughts on, let's assume $275 million is a good number next year, what kind of magnitude of cash return could we see to shareholders above your dividend again which is around $160 million a year?

Yes, we have established a clear track record of our intention to return value to shareholders. We aim to return 50% of our free cash flow. We will manage our debt next year, and we also prioritize our dividend. It seems likely that we will maintain our dividend at its current level. We will continue to evaluate this throughout the year and consider the macroeconomic environment. Additionally, we have discussed the possibility of special dividends, and our position on returning cash to shareholders remains unchanged.

Great. Thanks a lot, Dan.

You bet.

Good morning, Dan.

Good morning, Jeff.

I want to ask for a little help on two ideas from the press release together. First, Cabot said that it can maintain the flattish production in 2021 with lower spend, we just discussed that. And then, as with your preamble, there was the note that improving demand and diminishing supply implied tailwinds for nat gas pricing in 2021. One view seems quite conservative and the other one is more bullish. So I was wondering how do we put these two contrasting views together to think about what may be more probable or less probable for Cabot in 2021?

It's still early in the year. As usual, we shared our outlook for 2021 in February. At that time, we had the advantage of assessing the winter's impact and looking at the market conditions, which will help us define our 2021 capital expenditures more clearly. Currently, we are taking a conservative approach, but we believe we are well-positioned to generate significant free cash flow for our shareholders rather than for banks, which should be appealing. We have a cautious plan that we hope aligns with our expectations of commodity prices, with around $275 million in mind, and we feel confident about this at the moment. If market conditions remain disciplined and demand increases, particularly in the LNG sector, we have the capacity to adjust our program upward, but for now, we are comfortable with our lower capital expenditure plan for 2021 which will still deliver the same volumes.

And just to follow that up real quick. And I don't want to put words in your mouth, but it sounds like what you're saying is we've got a conservative program set up there is already going to generate attractive free cash. And if the market goes our way and we get better pricing, first and foremost, we're going to make even more free cash. And then maybe at some point, depending on signals, we might increase the activity as a follow-on. Is that fair, or am I reading too much into it?

I wish I could have said it as well as you did, Jeffrey.

Okay, great. And I'll ask a follow-up. Just a lot more specific, I just want to get your view on the cancellation of the Atlantic Coast pipeline, the likely completion of the Mountain View pipeline. And how you see that affecting the nat gas market in 2021, both macro and maybe on Appalachian basis as well? Thank you.

Thank you, Jeffrey. And Jeff Hutton is on the edge of his seat.

Good morning, Jeffrey. There's a lot to take in with the project. But in the grand scheme of things on pipeline development, we always felt like that project was fairly long because of the 600-mile, how many states they went through, et cetera, et cetera. And quite frankly, the high cost of that project, but also that project lands. It does tie in the trans for down to Station 165. We felt like that's quite a bit of gas we go into that market, obviously, there were some shippers that were optimistic that they'd be able to develop some more gas-fired generation down there. I still think that's the case. But I think there's also ample supply on the transport system to satisfy that demand. So initially, and even today, we still think that there was too much gas in that region. We were somewhat concerned that it would saturate the market to the point that it would bleed upstream into the D.C. area where we're actively marketing gas. And so, quite frankly, the cancellation of that project gives us a more optimistic view on pricing for that region.

Okay, great. That's very helpful. Thank you. And by the way, we'll see you next week.

Very good.

Thank you. Good morning.

Good morning, Brian.

I wanted to follow up on a couple of the points raised here earlier. First on that mechanism to return cash to shareholders. How are you thinking, you talked about the special dividend, but how are you thinking about more of a more codified variable dividend versus special dividend versus share repurchase when that time comes?

Yeah, we're socializing that now internally, Brian. We have not put a framework around a formulaic delivery of that special dividend or variable dividend. As you've seen in the past, we have, similar to our buybacks. We've made those decisions when we feel comfortable about the market. We see the near-term support in the market that allows us to generate a certain amount of incremental free cash. So, you know, I'm sorry I'm not specific on the formula, but we have not gotten to that formula internally.

Understood. Thank you. And then my follow-up is with regards to in-basin gas demand, can you give us the latest on what your expectations are for that market and how that also sets your view more broadly on what the outlook is for U.S. domestic gas demand, particularly from the power and industrial sectors?

Yeah, I'm going to make a comment then I want to turn it to Jeff, Brian, because it is an area that we are spending a great deal of time and focus on in-basin demand projects. But one of the most recent impetus, and catalysts that is, I think, driving now more attention to Northeast PA, as a location for demand projects, has been the agreement of tax credits that Pennsylvania will allocate to at least four projects that bring a large manufacturing or natural gas demand project to state and spend a certain amount of money, employ a certain amount of people, then they would receive hundreds of millions of dollars over the next 10 years of tax credits. That is a tremendous opportunity that is now in the books with the governor's signature. We have had discussions with in-basin demand projects, and we have had for a while, a business development group that is working this opportunity for us. We like the idea of in-basin projects. We can look that up on the tailgate of our gathering system. And it is an incremental realization to Cabot. I'll let Jeff talk a little bit about his thoughts in this regard.

Hey, good morning, Brian. The just a quick recap. In-basin demand in the Northeast corner, PA has picked up quite a bit of load over the last four, five years, somewhere in the neighborhood of 1.5 Bcf a day of new demand. And as you spread and look across the entire State of Pennsylvania, a lot of projects that are being built or have been built that are utilizing natural gas from the Pennsylvania area. So, it's all good, whether or not it's a Cabot-linked project or with others. But specifically, we've talked about this in the past, where we've identified a number of sites and locations with different acreage and terrain sizes with water, with rail, with power and obviously, with our gas supply. And we continue to talk to industries that are located in the Northeast, already have markets in the Northeast. There's been some new technology developed for some very unique projects that are good year-round loads, and so nothing to announce today. We have a huge amount of activity with different manufacturing associations and associations throughout that region, including local and county market development people. So, it's an ongoing process. We found some good opportunities, and we have some ideas that we're working toward, nothing definitive, but we're really happy with the 0.5 Bcf a day load that we currently have up there. And most of those deals, of course, are long-term in duration because of the nature of their locations.

Great. Thank you.

Thanks, Brian.

Hey guys. I was hoping to follow-up a little bit more on the kind of risk management/hedging strategy. As we sit here today, I mean it looks like futures curve in 2021 is offering a little bit north of 265, which seems like a very robust price compared to where we sit today and certainly one where I think Cabot's economics would be outstanding. Why not try to maybe put some kind of call or structure in place to protect some of that downside at this point? Certainly, recognize your bullish view on macro. But as you guys know, you're always kind of a warm winter away from potential challenges in the gas market. So, any thoughts you kind of have on that would be great.

We have certainly a discussion regularly internally with our hedge committee and the price we see out there in 2021 is actually north of the $265 million that we see today. It is our intent to mitigate, as you say, the downside of the macro market. We have all been disappointed in the past, more so disappointed in the recent past than pleasantly surprised. We do think that there are some fundamental points that we made in my remarks that are constructive to a supportive underpinning of the market. And, yes, it can go down, and as I mentioned that the risk of that type of downside, we're fully aware of. We think our program would deliver very well at $265 million. It is our intent to participate in the 2021 financial hedge market. And we'll do that appropriately with the vehicles, once we make the decision among the committee to do that. So we're thinking you like, Leo, we're pleased with where the market is right now. And we are, again, looking forward to participate in the hedge market. I can't tell you when, in advance, we plan to do something, but we do look at it every day.

Okay. That's great color. I just wanted to follow-up on your comments regarding 2021. I know it's not guidance and just sort of an outlook. But, I guess, flattish year-over-year production next year on my math kind of implies around a 4% decline versus fourth quarter 2020 levels. I know you guys certainly said that you think about this in a conservative way. I guess would that end up being a similar shape to what we saw in 2020, where your production was down a little bit early in the year due to lack of winter fracking and then maybe pick up from there? Just trying to understand the dynamic as to why you'd kind of be down versus 4Q if gas is strong next year.

I apologize for not being able to provide a detailed quarter-to-quarter cadence at this moment. However, I feel confident about our current outlook, which remains stable with lower capital in 2021. We are actively managing the cadence, influenced by various factors such as our size pads, winter conditions, and market expectations. We do not have a precise cadence established for the upcoming quarters. That said, if we reflect on last summer, we experienced gas prices around $1.60 to $1.70 between April and October. Looking ahead to 2021, if our assumptions about lower supply and higher demand this winter hold true, the market between April and October might approximate a $2.60 range. This suggests a significant price difference of nearly $1 during that timeframe. Our internal discussions continue regarding the cadence, and these are some considerations we take into account.

Okay. That’s great color. Thank you.

Good morning, Dan to you and your team there.

Hello, Charles.

Hey, Dan, I wanted to – this isn't something you guys really made a point this quarter, but I wondered if you could give us an update on the evolution of your – of the Upper Marcellus in your views. And I think the last time you guys really dove into it, we were talking about EURs that were about 90% of what the Lower Marcellus is. And so I'm wondering if you could just give us an update on if that view has evolved anymore. And if you're – if you have any plans for iterating on that zone or doing some more extensive testing in that zone, either in the back half of this year or in 2021?

Yes. And we have drilled some upper wells this year. The number though, Charles, for comparison between the lower is more 70-plus percent EUR, not 90%. And that's in our.

Always been the case.

Yes, that’s been our material, and that's always been the case. But the wells that we have drilled this year, and we've actually drilled uppers on three different pads and the wells in different locations in the field. And collectively, I'm not going to get grainier on it because a couple of wells have been on longer than the other wells that have come on more recently. But collectively, what we have seen is that our type curve on the upper is running slightly above, collectively, the type curve that we're using as our risk tight curve out there in the field for the upper.

Yes. So basically, what Dan's saying is that when you look at those pads currently, they've been on for a short period of time, but they're outperforming our projection for what the type curve would be for in that area. So we're very pleased with those results.

Yes. Got it. That's the kind of color I was looking for. I guess I misremembered and miscalibrated on that, but thank you for taking me out. Dan, I recognize that maybe this is a bit of a long shot, but is there anything – any comments you would care to make about the case that the Pennsylvania AG uncorked earlier this year with you guys?

Well, the AG has a number of companies have now been recognized by the AG and through their investigations. As you are aware that the charges are, of course, disputed matters but nonetheless, Cabot is cooperating with the AG, and we're – they have provided his staff with facts and data addressing the allegations directly. We are certainly telling Cabot's side of the story. It's undisputed up there that natural gas is naturally occurring in all the areas of Northeast Pennsylvania. And methane was up there in the rock prior to the oil and gas industry ever going up there. When we moved up there, it was a greenfield operation, no drilling had taken place, no production. And there was natural gas in the water systems up there. So we'll continue to work with AG, we're always employing our best practices to protect the environment and its operations and continue to be a leader in that regard. We do intend to be able to resolve this matter that is positive for all stakeholders.

Thanks for that color, Dan.

Thanks, Charles.

Yeah. Thanks. Good morning, guys. Just follow-up on a question before about the upper and the lower Marcellus. You talked about two decades of inventory. I just wanted to see how you could split that right now between the upper versus the lower? And at what price deck that would be using?

On our drill cadence, if you look at how we've laid out our long-term program. And we have shown in the past, we've shown our production and drilling going out into the 2040 period. We have go out into the latter part of 2020 decade with our lower drilling. And then subsequent to that, we move into the upper Marcellus drilling. And we have that drilling out into the 2040 period.

Got it. So it's kind of 10 years for the lower lease right now, it’s kind of maintenance cadence?

It's slightly less, John, than 10 years, but it goes out towards the end of the 2020 decade, yeah.

Got you. Okay. And then maybe just talking about that maintenance cadence. One of the benefits of staying at this lower level and not growing is that you can actually lower your base decline rate. I wanted to see where it was at the end of last year, where you think it might be at the end of this year? And if you were to just kind of hold things flat where that might be at the end of next year?

Our current decline rate is between 29% and 30%. I don't have the exact figure, but Steve Lindeman may be able to provide insight into our decline trends based on our reserves at the end of 2021.

Right. So what – like Dan said, right now, we're kind of running in the 29% to 30% range. As you go out three or four years and add to the base, we'll probably be running in the 24%, 25% range.

Got it. Understood. Thanks, guys.

Good morning and thank you for taking my questions.

You bet.

So Dan, you highlighted 8% free cash flow yield in 2021 at $275 million. I was looking at your 2019 financials. It looks like you guys were able to do $1.35 billion of discretionary cash flow at about $260 million. I know that had about $150 million of hedge gains. But just given the simple math there would get you to about $1.2 billion. And then, if I took your implied CapEx that was discussed earlier in the call, it feels like we should be much higher than 8% at $2.75 million. And so I guess my question is, is that conservatism on your part, or should we be thinking about basis expansion or maybe cash income taxes as you look toward a higher-priced environment?

Yes. I'm going to pitch the ball to Matt.

Hey, Kashy, yeah, I think you nailed it – you nailed it with the cash tax piece. Obviously, last year, we also had the benefit of higher – significantly higher deferred tax add back, because of tax reform, et cetera. So as we move forward now that we've maximized all the utilization of our NOLs and AMT, we're just not going to see those same tax benefits in the future. I'd add, of course, there's always conservatism in our guide as well, as you know.

Got it. Very helpful. I guess this high-class problem. And then as you think about capital spending, as you look at your capital spending or, I was looking at your capital spending, it seems like you guys have spent just under 60% of the budget, but you've completed well over that proportion of your targeted wells for the year. And so I guess my follow-up question was, are you guys seeing some sort of efficiencies or cost improvements? And is there anything to read-through for implications to the full year budget, or is this just more so timing related?

We have efficiency in our program. We decided to maintain our $575 million CapEx. It's midyear right now. It might be a conservative position, but we wanted the least noise in the release as we could deliver, and we thought that was appropriate.

Got it. That's very helpful. And if I could just sneak one more in, just follow-up on some earlier questions on the Upper Marcellus. I was just wondering, I know we've always talked about the 70% of – the upper 70% of the lower on the well performance front. Have you guys ever talked about just how to think about the difference in well costs between the two zones?

We have discussed our full development plans for the Upper Marcellus in a more indirect manner. To keep this brief, the Upper Marcellus represents a largely untapped area for us. With recent legislation allowing for longer laterals and new drilling techniques, we plan to establish a comprehensive framework for the Upper Marcellus with longer average laterals than we’ve achieved in the Lower Marcellus program. Specifically, we are looking at 12,000-foot laterals, which bring inherent efficiencies. In our current Lower Marcellus operations, we’ve seen costs of just over $700 per foot for drilling 11,000-foot laterals based on the data from the first and second quarters this year. It's important to note that our per-foot costs include all facility and site construction expenses, representing our full project costs. Additionally, we have efficient completion practices, using 2,500 pounds of proppant, which is more than some of our competitors. While this may increase our proppant costs, we believe our gas output justifies our approach. Overall, we expect significantly lower development costs for the Upper Marcellus, including the reuse of roads and equipment. Even though there may be a 70% cost comparison to the Lower, our anticipated returns for the Upper development look very promising.

That's excellent color. Thanks for all that.

Thank you, Allison. And once again, I would just like to say thanks again to those dedicated shareholders of Cabot, but also their gratitude to Cabot's team. They have been out there through this very difficult environment. Many of our field operators have been going to work every single day even though some of the corporate headquarters and office in Pittsburgh have honored the stay-at-home because of this pandemic. But those guys and girls out there in the field have gotten up every day to head out and do the work. And as you can see by our numbers, we've been able to deliver on our program and I'm very proud of the group. So, thanks again for the attention. Look forward to next quarter's call. Thank you.